CENTRAL VERMONT PUBLIC SERVICE CORP, 10-K405, 2000-03-10

CENTRAL VERMONT PUBLIC SERVICE CORP
10-K405, 2000-03-10
ELECTRIC SERVICES

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1999

OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to

Commission file number 1-8222
Central Vermont Public Service Corporation
(Exact name of registrant as specified in its charter)

Vermont 03-0111290
(State or other jurisdiction (IRS Employer
incorporation or organization) Identification No.)

77 Grove Street, Rutland, Vermont 05701
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code (802) 773-2711
________________________________________________________________________

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

Name of each exchange on which
Title of each class registered

Common Stock $6 Par Value New York Stock Exchange

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]

Cover page

State the aggregate market value of the voting stock held by
non-affiliates of the registrant: $126,134,855 based upon the closing
price as of January 31, 2000 of Common Stock, $6 Par Value, on the New
York Stock Exchange as reported in the Eastern Edition of the Wall
Street Journal.

Indicate the number of shares outstanding of each of the
registrant's classes of Common Stock: As of January 31, 2000, there
were outstanding 11,466,805 shares of Common Stock, $6 Par Value.

DOCUMENTS INCORPORATED BY REFERENCE

The Company's Definitive Proxy Statement relating to its Annual
Meeting of Stockholders to be held on May 2, 2000 to be filed with the
Securities and Exchange Commission pursuant to Regulation 14A under the
Securities Act of 1934, is incorporated by reference in Items 10, 11,
12, and 13 of Part III of this Form 10-K.

Cover page continued

Form 10-K - 1999

TABLE OF CONTENTS

Page
PART I

Item 1. Business................................................ 2
Item 2. Properties.............................................. 22
Item 3. Legal Proceedings....................................... 23
Item 4. Submission of Matters to a Vote of Security Holders..... 24

PART II

Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters.................................... 24
Item 6. Selected Financial Data................................. 25
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.................... 26
Item 8. Financial Statements and Supplementary Data............. 56
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.................... 90

PART III

Item 10. Directors and Executive Officers of the Registrant...... 90
Item 11. Executive Compensation.................................. 90
Item 12. Security Ownership of Certain Beneficial Owners and
Management............................................. 90
Item 13. Certain Relationships and Related Transactions.......... 91

PART IV

Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K............................................ 91
Signatures........................................................ 114

<PAGE>
PART I

Item 1. Business.

Overview.

Central Vermont Public Service Corporation (the "Company"),
incorporated under the laws of Vermont on August 20, 1929, is engaged
in the purchase, production, transmission, distribution and sale of
electricity. The Company has various wholly and partially owned
subsidiaries. These subsidiaries are described below.

The Company is the largest electric utility in Vermont and serves
140,866 customers in nearly three-quarters of the towns, villages and
cities in Vermont. This represents about 50% of the Vermont
population. In addition, the Company supplies electricity to one
municipal, one rural cooperative, and one private utility.

The Company's sales are derived from a diversified customer mix.
The Company's sales to residential, commercial and industrial customers
accounted for 61% of total mWh sales excluding mWh sales related to the
Virginia Power Alliance (2,986,682 mWh) for the year 1999. Sales to
the five largest retail customers receiving electric service from the
Company during the same period aggregated about 5% of the Company's
total electric revenues for the year. The Company's requirements
resale sales accounted for approximately 4%, entitlement sales
accounted for 10% and other resale sales which include contract sales,
opportunity sales, sales to NEPOOL and short-term system capacity sales
accounted for approximately 25% of total mWh sales for the year 1999.

Connecticut Valley Electric Company Inc. ("Connecticut Valley"), a
wholly owned subsidiary of the Company, incorporated under the laws of
New Hampshire on December 9, 1948, distributes and sells electricity in
parts of New Hampshire bordering the Connecticut River. It serves
10,427 customers in 13 communities in New Hampshire. About 2% of the
New Hampshire population resides in its service area. Connecticut
Valley's sales are also derived from a diversified customer mix.
Connecticut Valley's sales to residential, commercial and industrial
customers accounted for 99.5% of total mWh sales for the year 1999.
Sales to its five largest retail customers during the same period
aggregated about 17% of Connecticut Valley's total electric revenues
for the year 1999.

The Company also owns 56.8% of the common stock and 46.6% of the
preferred stock of Vermont Electric Power Company, Inc. ("VELCO").
VELCO owns the high voltage transmission system in Vermont. VELCO
created a wholly owned subsidiary, Vermont Electric Transmission
Company, Inc. ("VETCO"), to finance, construct and operate the Vermont
portion of the 450 kV DC transmission line connecting the Province of
Quebec with Vermont and New England. In addition, the Company owns
31.3% of the common stock of Vermont Yankee Nuclear Power Corporation
("Vermont Yankee"), a nuclear generating company. The Company also
owns 2% of the outstanding common stock of Maine Yankee Atomic Power
Company, 2% of the outstanding common stock of Connecticut Yankee
Atomic Power Company and 3.5% of the outstanding common stock of Yankee
Atomic Electric Company.

The Company also owns a real estate company, C.V. Realty, Inc. and
one wholly owned subsidiary created for the purpose of financing and
constructing a hydroelectric facility in Vermont. This hydroelectric
facility, owned by Central Vermont Public Service Corporation - East
Barnet Hydroelectric, Inc. became operational September 1, 1984 and has
been leased and operated by the Company since its in-service date.

In addition, the Company has a wholly owned non-utility
subsidiary, Catamount Resources Corporation, which was formed for the
purpose of holding the Company's subsidiaries that invest in
unregulated business opportunities. For additional information of the
Company's unregulated activities, see
PART II, Item 8 herein.

For Financial Information About Segments for the last three fiscal
years, See Part II, Item 8, Note 16-Segment Reporting.

REGULATION AND COMPETITION

State Commissions.

The Company is subject to the regulatory authority of the Vermont
Public Service Board ("PSB") with respect to rates, and the Company and
VELCO are subject to PSB jurisdiction respecting securities issues,
construction of major generation and transmission facilities and
various other matters. The Company is subject to the regulatory
authority of the New Hampshire Public Utilities Commission as to
matters pertaining to construction and transfers of utility property in
New Hampshire. Additionally, the Public Utilities Commission of Maine
and the Connecticut Department of Public Utility Control exercise
limited jurisdiction over the Company based on its joint-ownership
interest as a tenant-in-common of Wyman #4, a 619 MW generating plant
and Millstone Unit #3 ("Unit #3"), an 1149 MW nuclear generating
facility, respectively.

Connecticut Valley is subject to the regulatory authority of the
New Hampshire Public Utilities Commission ("NHPUC") with respect to
rates, securities issues and various other matters.

Federal Power Act.

Certain phases of the businesses of the Company and VELCO,
including certain rates, are subject to the jurisdiction of the Federal
Energy Regulatory Commission ("FERC") as follows: the Company as a
licensee of hydroelectric developments under PART I, and the Company
and VELCO as interstate public utilities under Parts II and III of the
Federal Power Act, as amended and supplemented by the National Energy
Act.

The Company has licenses expiring at various times under PART I of
the Federal Power Act for twelve of its hydroelectric plants. The
Company has obtained an exemption from licensing for the Bradford and
East Barnet projects.

Public Utility Holding Company Act of 1935.

Although the Company, by reason of its ownership of a utility
subsidiary, is a holding company, as defined in the Public Utility
Holding Company Act of 1935, it is presently exempt, pursuant to Rule
2, promulgated by the Commission under said Act, from all the
provisions of said Act except Section 9(a)(2) thereof relating to the
acquisition of securities of public utility affiliates.

Environmental Matters.

In recent years, public concern for the physical environment has
resulted in increased governmental regulation of environmental matters.
The Company is subject to these regulations in the licensing and
operation of the generation, transmission, and distribution facilities
in which it has interest, as well as the licensing and operation of the
facilities in which it is a co-licensee. These environmental
regulations are administered by local, state and Federal regulatory
authorities and concern the impact of the Company's generation,
transmission, distribution, transportation and waste handling
facilities on air, water, land and aesthetic qualities.

The Company cannot presently forecast the costs or other effects
which environmental regulation may ultimately have upon its existing
and proposed facilities and operations. The Company believes that any
such costs related to its utility operations would be recoverable
through the rate-making process. For additional information relating
to Electric Industry Restructuring see Part II Item 7 herein and refer
to Part II, Item 8 herein for disclosures relating to environmental
contingencies, hazardous substance releases and the control measures
related thereto.

Nuclear Matters.

The nuclear generating facilities of Vermont Yankee and the other
nuclear facilities in which the Company has an interest are subject to
extensive regulations by the Nuclear Regulatory Commission ("NRC").
The NRC is empowered to regulate the siting, construction and operation
of nuclear reactors with respect to public health, safety,
environmental and antitrust matters. Under its continuing
jurisdiction, the NRC may, after appropriate proceedings, require
modification of units for which operating licenses have already been
issued, or impose new conditions on such licenses, and may require that
the operation of a unit cease or that the level of operation of a unit
be temporarily or permanently reduced. Refer to Part II Item 8 herein
for disclosures relating to the shut down of the Maine Yankee,
Connecticut Yankee and Yankee Atomic Nuclear Power plants.

Competition.

Competition now takes several forms. At the wholesale level,
other electric power providers compete as suppliers to resale
customers. Another competitive threat is the potential for customers
to form municipally owned utilities in the Company's service territory.
At the retail level, customers have long had energy options such as
propane, natural gas or oil for heating, cooling and water heating, and
self-generation for larger customers. Changes anticipated as a result
of the National Energy Policy Act of 1992 and potential future change
in state regulatory policy may result in retail customers being able to
purchase electric power generated by competing suppliers for delivery
over the Company's transmission and distribution facilities.

Pursuant to Vermont statutes (30 V.S.A. Section 249), the PSB has
established as the service area for the Company the area it now serves.
Under 30 V.S.A. Section 251(b) no other company is legally entitled to
serve any retail customers in the Company's established service area
except as described below.

An amendment to 30 V.S.A. Section 212(a) enacted May 28, 1987
authorizes the Vermont Department of Public Service (Department) to
purchase and distribute power at retail to all customers of electricity
in Vermont, subject to certain preconditions specified in new sections
212(b) and 212(c). Section 212(b) provides that a review board
consisting of the Governor and certain other designated legislative
officers review and approve any retail proposal by the Department if
they are satisfied that the benefits outweigh any potential risk to the
State. However, the Department may proceed to file the retail proposal
with the PSB either upon approval by the review board or the failure of
the board to act within sixty (60) days of the submission.
Section 212(c) provides that the Department shall not enter into any
retail sales arrangement before the PSB determines and approves certain
findings. Those findings are (1) the need for the sale, (2) the rates
are just and reasonable, (3) the sale will result in economic benefit,
(4) the sale will not adversely affect system stability and reliability
and (5) the sale will be in the best interest of ratepayers.

Section 212(d) provides that upon PSB approval of a Department
retail sales request, Vermont utilities shall make arrangements for
distributing such electricity on terms and conditions that are
negotiated. Failing such negotiation, the PSB is directed to determine
such terms as will compensate the utility for all costs reasonably and
necessarily incurred to provide such arrangements. Such sales have not
been made in the Company's service area since 1993.

In addition, Chapter 79 of Title 30 authorizes municipalities to
acquire the electric distribution facilities located within their
boundaries. The exercise of such authority is conditioned upon an
affirmative three-fifths vote of the legal voters in an election and
upon the payment of just compensation including severance damages.
Just compensation is determined either by negotiation between the
municipality and the utility or, in the event the parties fail to reach
an agreement, by the Public Service Board after a hearing. If either
party is dissatisfied, the statute allows them to appeal the Board's
determination to the Vermont Supreme Court. Once the price is
determined, whether by agreement of the parties or by the PSB, a second
affirmative three-fifths vote of the legal voters is required.

There has been only one instance where Chapter 79 of Title 30 has
been invoked; the Town of Springfield acted to acquire the Company's
distribution facilities in that community pursuant to a vote in 1977.
This action was subsequently discontinued by agreement between
Springfield and the Company in 1985.

In the summer of 1997, the City of Claremont ("Claremont"), New
Hampshire engaged a consulting firm to conduct a study to determine
Claremont's options under New Hampshire law including the possible
municipalization of Connecticut Valley's service area located within
its jurisdiction. The City Council ("Council") appropriated
approximately $75,000 for purposes of the study which has been
completed. In May 1999, the City Council of Claremont considered
whether to publicly warn a vote to acquire the Company's facilities
located in Claremont and to establish a municipal electric utility
pursuant to N.H.R.S.A. Chapter 38 et. sec. By vote of six to three,
the Council voted to proceed towards the establishment of a municipal
electric utility and acquisition of Company facilities. This action
required that Claremont hold an election within one year of the
Council's action to determine if a majority of the qualified voters
will confirm the Council's decision. Should the Council's decision be
confirmed by Claremont voters, the Council will have thirty days from
the date of the confirming vote to notify the Company of its intention
to purchase all or such portion of the Company's plant and property
located within Claremont and such portion of the plant lying within the
municipality as the public interest may require. The company would
thereafter have sixty days to reply to the Claremont's inquiry. If
there is no agreement between the Company and Claremont, Claremont may
proceed to condemn the Company's facilities with proceedings before the
NHPUC as provided for in Chapter 38 and the FERC as provided for in its
Rule 35.26 (18CFR Chapter 1). On September 8, 1999, the City Council
voted to postpone indefinitely the citizens' vote on municipalization
which had been set for November 2, 1999. A group of Claremont citizens
opposed to a government electric takeover actively participated in the
November 2, 1999 municipal election, resulting in the election of three
challengers opposed to the idea, and the creation of a majority on the
city council against the municipalization of Connecticut Valley's
system. The Company cannot predict at this time when or if a citizens'
vote on municipalization will be held in connection with this
initiative.

No other municipality served by the Company, so far as is known to
the Company, has taken any formal steps in an attempt to establish a
municipal electric distribution system.

Competition in the energy services market exists between
electricity and fossil fuels. In the residential and small commercial
sectors this competition is primarily for electric space and water
heating from propane and oil dealers. Competitive issues are price,
service, convenience, cleanliness and safety.

In the large commercial and industrial sectors, cogeneration and
self-generation are the major competitive threats to electric sales.
Competitive risks in these market segments are primarily related to
seasonal, one-shift operations that can tolerate periodic power
outages, and for industrial customers with steady heat loads where the
generator's waste heat can be used in their manufacturing process.
Competitive advantages for electricity in those segments are the cost
of back up power sources, space requirements, noise problems, and
maintenance requirements.

In Docket DE 94-163, Order No. 21,683 (reh'g denied, Order No.
21,776), the NHPUC ruled that Public Service Company of New Hampshire's
("PSNH") rights to its franchise territory are not exclusive as a
matter of law. Connecticut Valley was an intervenor in that docket.
PSNH appealed the NHPUC's decision to the State of New Hampshire
Supreme Court, and Connecticut Valley has filed a brief with the New
Hampshire Supreme Court in favor of PSNH's position. The New Hampshire
Supreme Court upheld the NHPUC's position, but did not rule on just
compensation issues. The NHPUC ordered the petitioner to seek a ruling
from the FERC that its proposed operations were not a "sham
transaction." The petitioner failed to seek such a ruling, therefore,
the NHPUC closed this docket.

For a discussion relating to Electric Industry Restructuring in
Vermont and New Hampshire see PART II, Item 7 herein.

For a discussion relating to the Company's wholesale electric
business see Wholesale Rates below.

RATE DEVELOPMENTS

Vermont Retail Rates.

On September 22, 1997, the Company filed for a 6.6% or $15.4
million per annum, general rate increase to become effective June 6,
1998 (Docket No. 6018). Action on this case is stayed pending an
interlocutory appeal to the Vermont Supreme Court ("VSC").

Also on September 22, 1997, the Company filed a retail rate
redesign whose primary purpose was to eliminate seasonal rates. The
PSB has not yet acted on this request.

On June 12, 1998, the Company filed with the PSB a request for a
10.7% retail rate increase ($24.9 million of annualized revenues) to
become effective March 1, 1999 to cover primarily the higher power
costs that the Company will incur under the Vermont Joint Owners
("VJO") contract with Hydro-Quebec. In this proceeding the PSB delayed
the examination of the prudence and used-and-usefulness of the
Hydro-Quebec Contract pending the VSC's decision in the appeal of
Docket No. 6018. After extensive negotiation, on October 28, 1998 the
DPS filed a Memorandum of Understanding ("MOU") between it and the
Company which proposed a resolution of the issues other than power
costs under the Hydro-Quebec Contract. The proposed resolution
included, among other provisions, a final determination of the
Company's rate request except for issues of prudence and
used-and-usefulness of the Hydro-Quebec Contract, and a temporary, pro
forma Hydro-Quebec prudence and used-and-usefulness disallowance
modeled on the Hydro-Quebec disallowance which the PSB applied to Green
Mountain Power Corporation in its February 1998 rate order. To reflect
both the final and the temporary cost of service determinations, the
MOU proposed a "temporary rate increase" of 4.7% or $10.9 million on an
annualized basis effective with service rendered January 1, 1999. By
order dated December 11, 1998, the PSB approved the MOU in its
entirety. For additional information regarding rate increase requests
see PART II, Item 7 "Rates and Regulation" and Item 8 "Retail Rates"
herein.

<PAGE>
New Hampshire Retail Rates.

Connecticut Valley's retail rate tariffs, approved by the NHPUC,
contain a Fuel Adjustment Clause ("FAC") and a Purchased Power cost
Adjustment ("PPCA"). Under these clauses, Connecticut Valley recovers
its estimated annual costs for purchased energy and capacity which are
reconciled when actual data is available. On the basis of estimates of
costs, for 1998 and reconciliations from 1997, the combined 1998 FAC
and PPCA would have resulted in an increase in revenues of
approximately $2.1 million for 1998. Based on a motion by Claremont,
an intervenor, the NHPUC, in its order dated December 31, 1997, found
that Connecticut Valley was imprudent not to have terminated its
wholesale power contract with the Company and froze Connecticut
Valley's FAC and PPCA rates. Subsequently, the NHPUC, in deference to
a temporary restraining order issued by a federal district court,
allowed FAC and PPCA rates effective May 1, 1998 that would make the
Company whole for 1997 under collections, the 1998 under collections
incurred through April 30, 1998, and the increase in 1998 power costs.

On the basis of estimates of costs for 1999 and reconciliations
from 1998, the combined 1999 FAC and PPCA rates would have resulted in
a decrease in revenues of approximately $2.3 million for 1999. The
decrease was primarily caused by the elimination of the various under
collections from prior periods mentioned above. Claremont filed a
motion to determine the prudence of the 1999 power costs. However, by
agreement of the parties, including the NHPUC, the hearing was limited
to the mathematical calculation of the FAC and PPCA. An NHPUC order
allowed the decrease.

Effective June 1, 1999, pursuant to an appeals court order related
to the temporary restraining order issued by the federal district
court, the NHPUC reduced Connecticut Valley's FAC and PPCA rates to the
level in effect at December 31, 1997. Such level caused a $600,000
under collection of power costs for the subsequent seven-month period.

On the basis of estimates of costs for 2000 and reconciliations
from 1999, the combined 2000 FAC and PPCA rates would have resulted in
an increase in revenues of approximately $1.9 million for 2000. The
increase was primarily caused by the reduction of FAC and PPCA rates to
the level in effect at December 31, 1997. In fact, had the NHPUC not
ordered the reduction in rates to a level below cost of service
effective June 1, 1999, Connecticut Valley would have filed for a 4.8%
decrease. The NHPUC ordered the FAC and PPCA to remain unchanged at
the level in effect at December 31, 1997. See PART II, Item 7 herein
for additional information regarding New Hampshire Electric Industry
Restructuring and Item 8 Note 13 herein for information regarding
Retail Rates-New Hampshire.

Connecticut Valley's retail rate tariffs, approved by the NHPUC,
also provide for a Conservation and Load Management Percentage
Adjustment ("C&LMPA") for residential and commercial/industrial
customers in order to collect forecast Conservation and Load Management
("C&LM") costs. The forecast costs are updated effective January 1 of
each year and are reconciled when actual data are available. In
addition, Connecticut Valley's earnings reflect the recovery of lost
revenues related to fixed costs which Connecticut Valley fails to
otherwise recover as a result of C&LM activities. The C&LMPA further
provides for the future recovery of shareholder incentives related to
past C&LM activities. The NHPUC had approved the termination of C&LM
activities by Connecticut Valley at the end of 1998. The NHPUC issued
an order allowing an adequate level of recovery of lost revenues and
administration C&LM costs for 2000.

Connecticut Valley filed to eliminate seasonal rates and to
implement non-seasonal rates because the wholesale power market rules
had been revised in New England such that the disproportionate cost
emphasis placed on a utility's annual peak had been eliminated. Higher
winter rates during the time the Company would likely have experienced
its annual peak had signaled this cost emphasis to retail customers.
Pursuant to a stipulation signed by the NHPUC staff, the Office of the
Consumer Advocate, and Claremont, the NHPUC allowed non-seasonal rates
effective January 1, 2000.

Connecticut Valley also purchases power from several Independent
Power Producers ("IPPs"), who own qualifying facilities as defined by
the Public Utility Regulatory Policies Act of 1978. In 1999, under
long-term contracts with these qualifying facilities, Connecticut
Valley purchased 40,145 mWh, of which 37,309 mWh were purchased from
Wheelabrator Claremont Company, L.P., ("Wheelabrator") who owns a solid
waste plant. Connecticut Valley had filed a complaint with FERC
stating its concern that Wheelabrator has not been a qualifying
facility since the plant began operation. On February 11, 1998, the
FERC issued an Order denying Connecticut Valley's request of a refund
of past purchased power costs and lower future costs. The Company
filed a request for rehearing with the FERC on March 13, 1998 which was
denied. Subsequently, Connecticut Valley appealed to the D.C. Circuit
Court of Appeals which has yet to result in a decision.

See PART II, Item 7 herein for detailed information regarding
New Hampshire Electric Industry Restructuring.

Wholesale Rates.

The Company sells firm power to Connecticut Valley under a
wholesale rate schedule based on forecast data for each calendar year
which is reconciled to actual data annually. The rate schedule
provides for an automatic update of annual rates, as well as a
subsequent reconciliation to actual data. The Company filed and the
FERC approved (1) a revenue decrease of $226,000 or 1.9% for 1999 power
costs., (2) a reconciliation of 1998 revenues to actual costs which
resulted in an additional billing of $253,000, including interest, and
(3) a revenue decrease of $63,000 or 0.5% for 2000 power costs. An
NHPUC order dated February 28, 1997 regarding New Hampshire Electric
Industry Restructuring ordered, among other things, Connecticut Valley
to terminate the wholesale rate schedule with the Company.

On June 25, 1997, the Company filed with the FERC an application
for recovery of stranded costs and a notice of cancellation of the rate
schedule under which the Company sells firm power to Connecticut Valley
contingent upon the recovery of stranded costs. The stranded cost
obligation, expressed on a net present value basis as of January 1,
2000, is $44,925,000, would be authorized by the Company's open access
Transmission Service Tariff No. 7, and collected as a surcharge to the
transmission charges of any customer that uses the Company's
transmission system to wheel power for ultimate delivery within
Connecticut Valley's service area. The surcharge is expected to
recover the stranded costs over a ten-year period. By order dated
December 18, 1997, the FERC rejected the Company's filing on the
grounds that the transmission tariff was an inappropriate vehicle for
recovery. Pursuant to the FERC request in that order, the Company
filed a letter stating its intention to refile the stranded cost
recovery as an exit fee to the rate schedule under which the Company
sells firm power to Connecticut Valley. The Company did so on January
12, 1998. The FERC accepted the filing and bifurcated the proceeding,
first, to determine whether Connecticut Valley would become an
unbundled transmission customer of the Company and, second, to
determine the Company's expectation period for serving Connecticut
Valley and the allowable amount of the exit fee.

The Company filed a request with the FERC for an exit fee
mechanism to collect stranded costs resulting from the cancellation of
the contract with Connecticut Valley. The request described all of the
ways Connecticut Valley will become an unbundled transmission customer
of the Company subsequent to termination, and establishing the expected
period of service based upon the date of termination, whenever that
occurs, and the weighted average service life of its commitments to
power resources to serve Connecticut Valley. The stranded cost
obligation sought to be recovered through an exit fee expressed on a
net present value basis as of January 1, 2000, is approximately
$44,925,000.

During April and May 1999, hearings were held at the FERC before
the Administrative Law Judge ("ALJ") and a ruling of the ALJ is
expected in the first half of 2000. It is expected that the FERC will
act on the Judge's recommendations sometime thereafter.

For additional information regarding legal and regulatory
proceedings, see PART II, Item 7, Electric Industry Restructuring and
Item 8, Note 13, Retail Rates.

On March 1, 1995, the Company filed a comprehensive, open access
transmission tariff ("Tariff") with the FERC. The Tariff is designed
to provide firm and non-firm network transmission service, as well as
firm point-to-point service over the transmission systems of the
Company and Connecticut Valley. In addition, the Tariff would permit
customers to make use of the Company's contract rights to the
transmission facilities of the VELCO New England Power Company. The
Tariff would provide transmission service that is comparable to that
provided to native load customers. Charges for such service would be
based upon the Company's cost of service for transmission.

The Company prepared and filed the Tariff in anticipation of
developing business opportunities in the area of electric transmission
service. In addition, recent FERC orders led the Company to believe
that all electric utilities owning transmission facilities would be
required to prepare and file such a Tariff in the near future. FERC
issued a Notice Of Proposed Rulemaking ("NOPR") dated March 29, 1995,
promoting wholesale competition in the electric utility industry. The
Company's Tariff complies with many requirements proposed by the FERC
in its NOPR.

Nine parties intervened in the Company's Tariff filing. On
April 28, 1995, the FERC issued a deficiency letter asking for more
information in a number of areas. The Company filed a timely response
to the deficiency letter on June 14, 1995. Three parties filed
protests in response to the Company filing, and one additional party
filed a request for late intervention. The FERC accepted the Tariff
for filing on August 14, 1995, suspended it and set it for hearing.
The order allowed the Tariff to become effective August 15, 1995,
subject to refund and subject to the outcome of the Open Access NOPR
proceeding. The New Hampshire Electric Cooperative began taking
transmission service under the Tariff as of its effective date.

The Company entered into negotiations with FERC Staff and
intervenors and reached a settlement in principle in January 1996 on
all rate issues contained in the Tariff filing but one which was
settled in August 1996. The settlement provided for a fixed rate
effective from August 15, 1995 through July 8, 1996. The FERC has not
taken action on the settlement.

On July 9, 1996 the Tariff was replaced by a pro forma
transmission tariff ("Transmission Tariff") filed by the Company
pursuant to FERC Order No. 888. The Transmission Tariff, which was
approved by the FERC, embodied not only the open access principles set
forth in the FERC pro forma transmission tariff, but also continued to
embody the rate making and other Vermont and New England specific
non-rate terms and conditions. The Company has made a number of
filings to modify the Transmission Tariff in response to FERC orders
related to transmission tariffs of other utilities and to update
certain fixed charges and methodologies. All FERC orders received have
approved such modifications.

In 1997 the Company gave notice of termination effective December
31, 1999 to the seven customers taking transmission service under its
Transmission Tariff NO. 3. The seven customers began taking service
under the Transmission Tariff beginning January 1, 2000.

POWER RESOURCES

Overview.

The Company's and Connecticut Valley's energy generation and
purchased power required to serve their retail and firm wholesale
customers was 2,559,051 mWh for the year ended December 31, 1999. The
maximum one-hour integrated demand during that period was 420.5 mW,
which occurred on December 28, 1999. The Company's and Connecticut
Valley's total energy generation and purchased power in 1999, including
that related to all resale customers, was 6,771,767 mWh.

The following tabulation shows the sources of such energy and
capacity available to the Company and Connecticut Valley for the year
ended December 31, 1999. For additional information related to
purchased power costs, refer to PART II, Item 7 herein.

Year Ended December 31, 1999
Net Effective
Capability
12 Month Generated
Average and Purchased
mW mWh %
<S> <C> <C> <C>
WHOLLY-OWNED PLANTS:
Hydro....................... 40.7 180,530 2.7
Diesel and Gas Turbine..... 28.9 2,063 -
JOINTLY OWNED PLANTS:
Millstone #3................ 19.7 143,227 2.1
Wyman #4.................... 11.0 32,785 0.5
McNeil...................... 10.5 43,750 0.6
EQUITY OWNERSHIP IN PLANTS:
(Purchased)
Vermont Yankee.............. 158.5 1,264,044 18.7
MAJOR LONG-TERM PURCHASES:
Hydro-Quebec................ 172.3 1,329,609 19.6
OTHER PURCHASES:
System and other purchases.. 469.1 413,785 6.1
Small power producers....... 34.2 193,114 2.9
Unit purchases.............. 6.7 8,376 0.1
Entitlement purchases....... 10,651 0.2
NEPEX......................... - 163,151 2.4
VIRGINIA POWER ALLIANCE 752.0 2,986,682 44.1
------- --------- -----
TOTAL.................... 1,703.6 6,771,767 100.0
======= ========= =====

</TABLE>

Wholly Owned Plants.

The Company owns and operates 20 hydroelectric generating
facilities in Vermont which have an aggregate nameplate capability of
41.2 mW and two gas-fired and one diesel-peaking units with a combined
nameplate capability of
28.9 mW.

Jointly Owned Plants.

The Company has a joint-ownership interest in the following
generating and transmission plants:

<TABLE>
<CAPTION>
Net 1999
Fuel mW Generation Load Net Plant
Name Location Type Ownership Entitlement mWh Factor Investment
<S> <C> <C> <C> <C> <C> <C> <C>
Millstone Unit #3 Waterford, Nuclear 1.73% 20 143,227 82% $49,900,626
Connecticut

Wyman #4 Yarmouth, Oil 1.78% 11 32,785 34% $ 1,287,181
Maine

Joseph C. McNeil Burlington, Various 20.00% 10.6 43,750 47% $ 7,303,506
Vermont

Highgate Trans- Highgate Springs, 47.35% N/A N/A N/A $ 8,497,614
mission Facility Vermont

</TABLE>

The Company receives its share of the output and capacity of
Unit #3, an 1149 mW nuclear generating facility (see discussion below);
Wyman #4, a 619 mW generating facility and Joseph C. McNeil, a 53 mW
generating facility.

The Highgate Convertor, a 225 mW facility is directly connected to
the Hydro-Quebec System to the north of the Convertor and to the VELCO
System for delivery of power to Vermont Utilities. This facility can
deliver power either direction, but normally delivers power from
Hydro-Quebec to Vermont.

The Company is responsible for its share of the operating expenses
of these facilities.

Equity Ownership in Plants.

In 1966 the Company purchased 35% of the Vermont Yankee common
stock and was entitled to receive a like percentage of the output of
the unit. In late 1969 and early 1970, the Company sold at cost a
combined total of 3.7% of its original equity investment and currently
resells at cost 3.9% of its entitlement. The Company's current equity
ownership and net entitlement percentages are 31.3 and 31.1,
respectively.

The Atomic Energy Commission, now the ("NRC"), granted a full-term
(40-year), full power operating license for the Vermont Yankee plant,
which was to expire in December 2007. On December 17, 1990 the NRC
issued an amendment of the operating license extending its term to
March 21, 2012.

Vermont Yankee's net capability is 522 mW of which about 162.6 mW
(See Note 1) is the Company's net entitlement. Vermont Yankee's plant
performance for the past five years is shown below:
<TABLE>
<CAPTION>
Availability Capacity
Factor Factor
(See Note 2) (See Note 3)

Vermont Yankee was shut down for scheduled refueling outages in
1995, 1996, 1998 and 1999.

As described in the overview section above, the Company is also a
stockholder, together with other New England electric utilities, in the
following three nuclear generating companies: Maine Yankee Atomic
Power Company, Connecticut Yankee Atomic Power Company and Yankee
Atomic Electric Company.

<TABLE>
<CAPTION>
Net Company's
Company Capability Entitlement
<S> <C> <C>
Maine Yankee.................. (See Note 4) (See Note 4)
Connecticut Yankee............ (See Note 4) (See Note 4)
Yankee Atomic................. (See Note 4) (See Note 4)
</TABLE>

The Company is obligated to pay its entitlement percentage of the
operating expenses of Vermont Yankee and the other Yankee companies,
including depreciation and a return on invested capital, whether or not
the plant is operating. The Company is obligated to contribute its
entitlement percentage of the capital requirements of Vermont Yankee
and Maine Yankee and has a similar, but more limited obligation to
Connecticut Yankee. The Company's entitlement percentages are
identical to the ownership percentages except that Vermont Yankee's
entitlement percentage is 35%. For additional information regarding
Equity Ownership in Plants, including the potential sale of Vermont
Yankee, refer to PART II, Item 8 herein.

_______________
Notes:
(1) Currently, the Company resells at cost, through VELCO, about 20 MW of
its original entitlement to other Vermont utilities.

(2) "Availability Factor" means the hours that the plant is capable of
producing electricity divided by the total hours in the period.

(3) "Capacity Factor" means the total net electrical generation divided
by the product of the maximum design electrical rating capacity of
514 through April 30, 1995 and 522 effective May 1, 1995, multiplied
by the total hours in the period.

(4) Maine Yankee, Connecticut Yankee and Yankee Atomic permanently ceased
power operations of their Nuclear Power Plants. See Decommissioning
Expense discussion below.

Decommissioning Expense.

Each of the Yankee companies has developed its own estimate of the
cost of decommissioning its nuclear generating unit. These estimates
vary depending upon the method of decommissioning, economic
assumptions, site and unit specific variables, and other factors. Each
of the Yankee Companies includes charges for decommissioning costs in
the cost of capacity, as approved by the FERC.

The Company's entitlement percentage of decommissioning costs for
Vermont Yankee, Maine Yankee, Connecticut Yankee and Yankee Atomic is
as follows (dollars in millions):
<TABLE>
<CAPTION>
CVPS's
Total Share of
Date of Estimated CVPS's Funded
Study Obligation Obligation Obligation
<S> <C> <C> <C> <C>
Nuclear generating companies:
Vermont Yankee 1993 $312.7 $109.4 $73.4
Maine Yankee 1998 $343.9 $6.9 $3.6
Connecticut Yankee 1996 $426.7 $8.5 $3.6
Yankee Atomic 1994 $370.0 $13.0 $5.4
</TABLE>
Vermont Yankee's current decommissioning cost study is based on a
1994 site study. The FERC approved settlement agreement allowed $312.7
million, in 1993 dollars, as the estimated decommissioning cost. Based
on the study's assumed cost escalation rate of 5.4% per annum and an
expiration of the Plant's operating license in the year 2012, the
estimated current cost of decommissioning is $428.7 million and, at the
end of 2012, is approximately $816.6 million. The present value of the
pro rata portion of decommissioning costs recorded to date is $290.0
million of which the Company's share is $101.5 million.

Under the FERC approved settlement agreement, Vermont Yankee was
required to file with FERC an updated decommissioning cost study by
April 1, 1999. On May 13, 1999, in light of the ongoing discussions
involving the possible sale of the Vermont Yankee Nuclear Power plant,
the FERC approved a settlement agreement extending the required filing
date to April 1, 2000.

On November 17, 1999, Vermont Yankee executed an Asset Purchase
agreement with AmerGen Energy Co. The sale of the nuclear generating
plant would transfer responsibility for decommissioning the plant to
the new owner. The price to be paid by AmerGen for the plant and
property will range from $10 million to $23.5 million depending on when
the sale occurs. Additionally, Vermont Yankee's current owners will
make a one-time payment of $54.3 million to pre-pay the plant's
decommissioning fund at $312.7 million. In return AmerGen will assume
full responsibility for all future operating costs and the estimated
$816.6 million price tag for decommissioning the plant at the end of
its operating license in 2012. The agreement is subject to several
conditions, including approvals or specific rulings by various
regulatory authorities. As such, execution of the agreement does not
provide assurance that the sale will occur. This agreement will also
involve the Company entering into a contract to purchase a portion of
the power produced by this plant.

During 1996, Vermont Yankee initiated a Design Basis Documentation
project expected to be complete by December 31, 2001. This project was
undertaken to incorporate all design documentation into a centralized
system. The objective is to ensure that Vermont Yankee maintains its
safety margins in connection with any plant modifications. The Design
Basis Documentation project will create a set of design basis documents
which will support more efficient systematic problem solving,
maintenance, and system overview. This effort supports the safe, cost
effective, long term operation of the Vermont Yankee Plant. Vermont
Yankee received FERC approval in 1996 to defer these unrecovered study
costs and amortize the costs through billings to Sponsors over the
remaining license life of the Plant. The Company's 35% share of the
total cost for this Project is expected to be between $5.5 million and
$6.2 million. See Part II Items 7 and 8 for additional information.

The Company owns interests in two of the five nuclear plants
operated by Northeast Utilities ("NU"): 1) a 2% equity interest in the
Connecticut Yankee Atomic Power Company and 2) a 1.7303%
joint-ownership interest in Unit #3 of the Millstone Nuclear Power
Station.

The Company is responsible for paying its ownership percentage of
decommissioning costs for Unit #3. Based on a 1997 study, the total
estimated obligation at December 31, 1999 was approximately $619.5
million and the funded obligation was about $229.0 million. The
Company's share for the total obligation and funded obligation was
approximately $10.7 and $4.0 million, respectively. These costs are
included in depreciation expenses.

Although the estimated costs of decommissioning are subject to
change due to changing technologies and regulations, the Company
expects that the nuclear generating companies' liability for
decommissioning, including any future changes in the liability, will be
recovered in their rates over their operating or license lives. See
PART II, Item 8 for information regarding the premature shutdown of the
Maine Yankee, Connecticut Yankee and Yankee Atomic nuclear power
plants.

The Company remains actively involved with the other non-operating
minority joint-owners of Unit #3. This group is engaged in various
activities to monitor and evaluate NU and Northeast Utilities Service
Co.'s efforts relating to Unit #3. On August 7, 1997, the Company and
eight other non-operating owners of Unit #3 filed a demand for
arbitration with Connecticut Light and Power Company and Western
Massachusetts Electric Company, both NU affiliates, and lawsuits
against NU and its trustees. The arbitration and lawsuits seek to
recover costs associated with replacement power, operation and
maintenance costs and other costs resulting from the lengthy outage of
Unit #3. The non-operating owners claim that NU and two of its wholly
owned subsidiaries failed to comply with NRC's regulations, failed to
operate the facility in accordance with good operating practice and
attempted to conceal their activities from the non-operating owners and
the NRC.

On September 15, 1999, NU announced that it intends to auction its
nuclear generating plants, including Unit #3. We cannot predict at
this time the effect of such an auction, if it occurs, on the Company
or on the ongoing litigation.

On October 27, 1999, NU and New England Power Company, ("NEP"),
disclosed that NU had reached an agreement with NEP and Montaup
Electric Company ("MEC"), two of the non-operating minority joint
owners, to settle their claims in the arbitration and lawsuits. The
settlement involves payment of fixed and contingent amounts to NEP and
MEC and the inclusion of their Unit #3 interests in NU's auction of the
plant. On January 28, 2000, Central Maine Power Company ("CMP") also
one of the non-operating minority joint owners, disclosed that NU and
CMP had reached an agreement to settle CMP's claims in the arbitration
and litigation on terms similar to the NEP and MEC settlement. The
other non-operating minority joint owners, including the Company,
remain active in the arbitration and lawsuits and in seeking to settle
our claims against NU.

In 1982 the State of Maine enacted legislation that requires the
development of a decommissioning trust fund for the Maine Yankee
nuclear plant. This statute also provides that, if the trust has
insufficient funds to decommission the plant, the licensee, Maine
Yankee, is responsible for the deficiency and, if the licensee is
unable to provide the entire amount, the owners of the licensee are
jointly and severally responsible for the remainder. The definition of
owner under the statute includes the Company. It is expected that any
payments required by the Company under these provisions would be
recovered through rates.

Nuclear Fuel.

Vermont Yankee has several "requirements 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 the option to extend
the agreements. Negotiation of new contracts or renegotiation of
existing contracts routinely occurs, often focusing on one of the four
components at a time. The price of the 1999 reload was approximately
$21 million. Future refueling 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 $0.6 million in 1997 which was recorded as an offset to
nuclear fuel expense. The potential future payments that Vermont
Yankee could receive over a ten year period, range from $0.0 million to
$1.6 million. No payments were received in either 1999 or 1998 by
Vermont Yankee under this agreement. Due to the uncertainty of this
transaction, the potential benefits will be recorded on a cash basis.

Under the Nuclear Waste Policy Act of 1982, the United States
Department of Energy ("DOE") is responsible for the selection and
development of repositories for and the disposal of spent nuclear fuel
and high-level radioactive waste. Vermont Yankee, as required by that
Act, has signed a contract with the DOE to provide for the disposal of
spent nuclear fuel and high-level radioactive waste from its nuclear
generation station beginning no later than January 31, 1998; however,
this delivery schedule has not been met and is expected to be delayed
significantly. It is not certain when the DOE will accept spent
nuclear fuel and high-level radioactive waste from Vermont Yankee and
other owners of nuclear power plants. These delays by the DOE have
caused Vermont Yankee to consider other costly alternatives for storing
high level waste.

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 6, 1983, and a fee payable quarterly equal to
one mill per kilowatt hour of nuclear generated and sold electricity
after April 6, 1983. Although the $39.3 million for the one-time fee
has been collected from the Sponsors in rates, Vermont Yankee has
elected to defer payment to the DOE as permitted by the DOE contract.
The fee plus accrued interest must be paid no later than the first
delivery of spent fuel to the DOE repository. Interest accrues on the
unpaid obligation based on the thirteen-week Treasury Bill rate and is
compounded quarterly. Through 1999, Vermont Yankee accumulated
$101.5 million in an irrevocable trust to be used exclusively for
defeasing this obligation ($108.8 million including accrued interest)
at some future date, provided the DOE complies with the terms of the
aforementioned contract.

Vermont Yankee has primary responsibility for the interim storage
of its spent nuclear fuel. The plant is currently able to operate with
the ability to discharge the entire reactor core to the spent fuel
storage pool through the 2001 refueling outage. In 1999, Vermont
Yankee received an NRC license amendment allowing the installation of
additional storage racks in the existing spent fuel pool. When
installed, the additional storage racks will increase the capacity of
the spent fuel to allow full core discharge capability through year
2008 refueling outage. Vermont Yankee is also investigating other
options for additional storage capacity beyond the year 2001.

In November 1997, the U.S. District Court of Appeals for the D.C.
Circuit ruled that the lack of an interim storage facility does not
excuse the DOE from meeting its contract obligation to begin accepting
spent nuclear fuel no later than January 31, 1998. The ruling said,
however, that the 1982 federal law could not require the DOE to accept
waste when it did not have a suitable storage facility. The court
directed the plaintiffs to pursue relief under terms of their contracts
with the DOE. Based on this ruling, since the DOE did not take the
spent nuclear fuel as scheduled, it may have to pay contract damages.

In May 1998, the same court denied petitions from 60 states and
state agencies and 41 utilities, including Vermont Yankee, asking the
court to compel the DOE to submit a program, beginning immediately, for
disposing of spent nuclear fuel. The petitions were filed after the
DOE defaulted on its January 31, 1998 obligation to begin accepting the
fuel. The court directed Vermont Yankee and other plaintiffs to pursue
relief under the terms of their contracts with the DOE.

In a petition filed in August 1998, the court's May 1998 decision
was appealed to the U.S. Supreme Court. In November 1998, the Supreme
Court declined to review the lower court ruling that said utilities
should go to court and seek monetary damages from the DOE. Also, in
November 1998, the U.S. Court of Federal Claims ruled that the DOE
violated a commitment to remove spent nuclear fuel from civilian
nuclear power plants. The claims court issued a ruling of summary
judgment in favor of Yankee Atomic Power Co., which was the first of
ten utilities to sue at the court a specialized body that hears only
money disputes. The claims court is scheduling further proceedings to
decide the amount of damages.

The average energy and capacity costs to the Company of energy
generated at the Vermont Yankee plant was 4.68, 4.78, 4.06, 5.81 and
5.14 cents per kWh for the years 1995 through 1999, respectively.

The Company has been advised by the companies operating other
nuclear generating stations in which the Company has an interest that
they have contracted for certain segments of the nuclear fuel
production cycle through various dates. Contracts for the remainder of
the fuel cycle will be required but their availability, prices and
terms cannot be predicted.

Nuclear Liability and Insurance.

The Price-Anderson Act currently limits public liability from a
single incident at a nuclear power plant to $9.7 billion. Beyond that
a licensee is 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 $9.5 billion per incident by assessing $88.1
million against each of the 108 reactor units that are currently
subject to the Program in the United States, 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. Currently the Company's interests in the
nuclear power units are such that it could become liable for an
aggregate of approximately $3.7 million of such maximum assessment per
incident per year.

Major long-term purchases.

Canadian Purchases - Under various contracts, the Company
purchases from Hydro-Quebec capacity and associated energy. Under the
terms of these contracts, the Company is required to pay certain fixed
capacity costs whether or not energy purchases above a minimum level
described in the contracts are made. Such minimum energy purchases
must be made whether or not other less expensive energy sources might
be available.

The company is purchasing varying amounts of power from
Hydro-Quebec under the VJO contract through 2016. Related contracts
were negotiated between the Company and Hydro-Quebec which in effect
alter the terms and conditions contained in the VJO contract, reducing
the overall power requirements and cost of the original contract.

The average annual amount of capacity that the Company will
purchase through October 31, 2016 is 132 mW. The total commitment to
purchase power under these contracts on a nominal basis is
approximately $975 million net of power sellbacks over the contract
term. In February 1996, the Company reached an agreement with
Hydro-Quebec which lowered the 1997 cost of power by approximately
$5.8 million. As part of this agreement, the Company delivers to
NEPOOL under existing firm energy contracts or joint marketing
activities 54 mW of Phase II transmission capacity for a five-year
period which began July 1, 1996 through June 30, 2001.

In the early phase of the VJO contract, two sellback contracts
were negotiated, the first delaying the purchase of about 25 mW of
capacity and associated energy, the second reducing the net purchase of
Hydro-Quebec power. In 1994, the company negotiated a third sellback
arrangement whereby the Company receives an effective discount on up to
70 mW of capacity starting in November 1995 for the 1996 contract year
(declining to 30 mW in the 1999 contract year). In exchange for this
sellback, Hydro-Quebec has the right to reduce capacity deliveries by
up to 50 mW beginning as early as 2004 until 2015, including the use of
a like amount of the Company's Phase I/II facility rights and the
ability to reduce the amounts of energy delivered during a five-year
term beginning in 2000.

There are specific contractual step up provisions that provide
that in the event any VJO member fails to meet its obligation under the
contract with Hydro-Quebec, the balance of the VJO participants,
including the Company, will "step up" to the defaulting party's share
on a pro-rata basis. As of December 31, 1999 the Company's VJO
obligation is approximately 43% or $975 million on a nominal basis over
the contract ending in 2016. The total VJO contract obligation on a
nominal basis over the term of the contract is approximately
$2.1 billion.

During January 1998, a significant ice storm affected parts of New
England and the Province of Quebec, Canada. This storm damaged major
components of the Hydro-Quebec transmission system over which power is
supplied to Vermont under the VJO contract with Hydro-Quebec. This
resulted in a 61-day interruption of a significant portion of scheduled
contractual energy deliveries into Vermont. The ice storm's effect on
Hydro-Quebec's transmission system caused the VJO to examine
Hydro-Quebec's overall reliability and ability to deliver energy. On
the basis of that examination, the VJO determined that Hydro-Quebec has
been and remains unable to make available capacity with the degree of
firmness required by the VJO Power Contract. That determination has
prompted the VJO to initiate an arbitration proceeding. In the
arbitration, the VJO is seeking to terminate the contract, to recover
damages associated with Hydro-Quebec's failure to comply with the
contract, and to recover capacity payments made during the period of
non-delivery.

In September 1999 an initial two weeks of hearings were held
dealing primarily with issues of contract interpretation. Additional
hearings dealing with technical issues will be held in the second and
third quarters of 2000. The company expects a decision by the end of
2000. In accordance with a PSB Accounting Order, the Company has
deferred incremental costs associated with this arbitration of
approximately $2.0 million. Recovery of these costs will be determined
in the next rate proceedings.

Merrimack #2

Until its termination on April 30, 1998, the Company purchased
power and energy from Merrimack #2 pursuant to a contract dated
July 16, 1966 entered into by and between VELCO and Public Service
Company of New Hampshire ("PSNH"). Pursuant to the contract, as
amended, VELCO agreed to reimburse PSNH, in the proportion which the
VELCO quota bears to the demonstrated net capability of the plant, for
all fixed costs of the unit and operating costs of the unit incurred by
PSNH, which are reasonable and cost-effective for the remaining term of
the VELCO contract. In early 1998, PSNH took the Merrimack Unit #2
facility off line, shut it down and commenced a maintenance outage. In
February, March and April of 1998, PSNH billed VELCO for costs to
complete the maintenance outage. VELCO disputes the validity of a
portion of the charges on grounds that the maintenance performed at the
unit was to extend the life of the Merrimack plant beyond the term of
the VELCO contract and that the charges in connection with said
investments were not reasonable and cost-effective for the remaining
term of the VELCO contract. The Company estimates the portion of the
disputed charges allocable to the Company could be as much as
$.5 million on a pre-tax basis.

Other Purchases.

Cogeneration/Independent Power Qualifying Facilities - A number of
independent producers using hydroelectric, biomass, and refuse-burning
generation are currently producing energy that the Company is
purchasing. For the year ended December 31, 1999, the Company received
193,114 mWh from these sources for which it paid $21,187,747.

The Company, through VELCO, is a participant in NEPOOL, which has
been open to all investor-owned, municipal, and cooperative utilities
in New England under an agreement in effect since 1971 and amended from
time to time. The Restated NEPOOL Agreement offers membership
privileges to any entity which is engaged or proposes to engage in the
wholesale or retail electric power business in New England. NEPOOL's
function has changed in response to the growing climate of competition
and the FERC requirements for open access transmission across systems.
A new organization, an Independent System Operator ("ISO"), has been
formed to operate the bulk power generation and transmission systems,
to administer the regions open access transmission tariff, and to
operate the electric ISO wholesale power market for New England. The
bilateral market for transactions directly between NEPOOL participants
will continue as an alternative to the ISO wholesale spot market.

The ISO is governed by the principles put forth in the FERC Order
888 under rules defined by NEPOOL and approved by FERC. They include:
to provide independent, open and fair access to the regional
transmission system, to establish a non-discriminatory governance
structure, to facilitate market-based wholesale electric transactions,
and to ensure the efficient management and reliable operation of the
regional bulk power system.

The ISO has established a bidding system for the newly defined
generation products; it will form the basis for the ISO's economic
dispatch (based on bid prices) of the generation products. This system
provides a settlement mechanism which will price the residual of a
given generation product that is excess to a participant's own needs,
and is offered to the ISO wholesale power market. A participant will
pay, as before, the actual costs for its generation products used to
serve its load or takes to market. A participant will submit a bid for
its generation products to the ISO, and if the bid is accepted and if
the participant supplies residual generation products to the ISO
wholesale market, the participant will receive the market clearing
price based on the highest bids accepted for the residual product. If
a participant needs to purchase from the ISO wholesale market to serve
its load, those purchases will be made at market clearing price.

The ISO will also provide the main market place for participants
to secure open access transmission for transactions delivered on the
Pool Transmission Facilities ("PTF"). Over the next several years, the
pricing differences that had existed between transmission systems
within NEPOOL will disappear as a NEPOOL-wide transmission pricing
arrangement for all PTF and the open access tariffs of local network
providers will offer access to all other transmission facilities.

The Company's peak demand for 1999 occurred on December 28 and
equaled 420.5 mW. At the time of this peak, the Company had a reserve
margin of 29%. NEPOOL's peak for the year occurred on July 7, 1999 and
totaled 22,544 mW.

Power Resources - Future.

The Company has generally sufficient power under contract to
supply its current franchise obligations for the near-term prior to any
advent of Retail Wheeling. In addition, the Company will continue to
utilize cost effective demand side management programs where
appropriate. The Company will offer other retrofit energy efficiency
services as part of a least-cost plan for electricity delivery. In
addition, the Vermont state-wide Energy Efficiency Utility will offer
energy efficiency services funded by a line item charge on each
customer's bill.

The Company expects to actively manage this portfolio of supply
and demand side resources over the near-term, as it has in the past, to
minimize net power costs for its ratepayers and shareholders. It is
unclear what the Company's load responsibilities will be upon the
advent of Retail Wheeling. The certainty, timing and nature of these
events will be largely determined by legislative and regulatory actions
at the state and national levels.

TRANSMISSION

Vermont Electric Power Company, Inc.

VELCO engages in the operation of a high-voltage transmission
system which interconnects the electric utilities in the State
including the areas served by the Company. VELCO is also engaged in
the business of purchasing bulk power for resale, at cost, to the
Company and the other electric utilities (cooperative, municipal and
investor-owned) in Vermont (the "Vermont utilities") and transmitting
such power for the Vermont utilities. Refer to Item 8 herein for a
discussion of the 1985 Four Party Agreement between the Company, VELCO
and two other major distribution companies in Vermont.

VELCO provides transmission services for the State of Vermont,
acting by and through the Department, and for all of the electric
distribution utilities in the State of Vermont. VELCO is reimbursed
for its costs (as defined in the agreements relating thereto) for the
transmission of power for such entities. The Company, as the largest
electric distribution utility in Vermont, is the major user of VELCO's
transmission system.

The Company owns 34,083 shares (56.8%) of the Class B common stock
of VELCO, the balance being owned by other Vermont utilities. Each
share of Class B common stock has one vote. The Company also owns
46,624 shares (46.6%) of the Class C preferred stock of VELCO, the
balance being owned by other Vermont utilities. Shares of Class C
preferred stock have no voting rights except the limited right to vote
VELCO's shares of common stock in Vermont Electric Transmission
Company, Inc. (VETCO) if certain dividend requirements are not met.

NEPOOL Arrangements.

VELCO participates for itself and as agent for the Company and
twenty-one other Vermont utilities in NEPOOL.

Capitalization.

VELCO has authorized 92,000 shares of Class B common stock, $100
par value, of which 60,000 shares were outstanding on December 31, 1999
and 125,000 shares of Class C preferred stock, of which 100,000 shares
were outstanding at December 31, 1999. On that date there were
authorized and outstanding three issues of First Mortgage Bonds,
aggregating $29,236,000, issued under an Indenture of Mortgage dated as
of September 1, 1957, as amended, between VELCO and Bankers Trust
Company, as Trustee (the "VELCO Indenture"). The issuance of bonds
under the VELCO Indenture is unlimited in amount but is subject to
certain restrictions.

New transmission and associated facilities will be required by
VELCO in 2000 to transmit power to Vermont utilities. The costs of
such facilities are presently estimated at $15,170,314 including
allowance for funds used during construction calculated at a rate of
approximately 6.5%. For a description of VELCO's properties, see
"VELCO" under Item 2.

Management.

In 1957 VELCO entered into an agreement (the "Three-Party
Agreement") whereby the Company and Green Mountain agreed that, if
VELCO transmits firm power it owns (which VELCO does not now do), VELCO
would have the right to purchase all such firm power not sold to
others. As such, VELCO would have the obligation to pay associated
operating expenses, debt service and taxes. In connection with the
transfer to VELCO of entitlements of the output of the Vermont Yankee
plant, the Company and Green Mountain Power Corporation entered into a
Three-Party Transmission Agreement, dated November 21, 1969, as
amended, whereby they have agreed to pay transmission charges thereon
in an aggregate amount sufficient, with VELCO's other revenues, to pay
all of VELCO's expenses including capital costs. VELCO's Bonds are
secured by a first mortgage on the major part of VELCO's transmission
properties and by the assignment to the Trustee of the Three-Party
Agreement, the Three-Party Transmission Agreement and certain other
contracts as specified in the VELCO Indenture. See Item 8 herein for
information relating to the 1985 Four-Party Agreement.

Vermont Electric Transmission Company, Inc.

In connection with the importing of Canadian power, VELCO has
created a wholly owned subsidiary, VETCO, to construct, finance, own
and operate the Vermont portion of the transmission line which connects
the Hydro-Quebec lines at the Canadian border to the lines of New
England Electric Transmission Corporation, a subsidiary of New England
Electric System, at the New Hampshire border on the Connecticut River.
VETCO entered into a Capital Funds Agreement with VELCO pursuant to
which VETCO may request up to $12,500,000 (of which $10,000,000 was
contributed as of December 31, 1999) of capital contributions from
VELCO and has entered into Transmission Line Support Agreements with 20
New England utilities, including VELCO as representative for 14 Vermont
utilities, pursuant to which those utilities have agreed to pay the
transmission line costs, whether or not the line is operational.
VELCO, as such representative, has entered into a similar agreement
with New England Electric Transmission Corporation with respect to the
New Hampshire portion of the DC transmission line and the DC/AC
converter station. Pursuant to a Vermont Participation Agreement and a
Capital Funds Support Agreement with VELCO and 14 Vermont electric
distribution utilities, including the Company, assume their pro rata
share (based upon 1980 sales) of the benefits and obligations of VELCO
under the Support Agreements and the VETCO Capital Funds Agreement.

VETCO has authorized 10 shares of common stock, $100 par value,
all of which were outstanding on December 31, 1999 and owned by VELCO,
with each share having one vote. During 1986 VETCO paid off its
construction financing by issuing $37,000,000 of secured notes,
maturing in 2006, and receiving a $9,999,000 equity contribution from
VELCO. The notes are secured by a First Mortgage on the major part of
VETCO's transmission properties and by the assignment of its rights
under the Support Agreements.

Phase I and Phase II.

The Company participated with other electric utilities in the
construction of the Phase I Hydro-Quebec transmission facilities in
northeastern Vermont, which were completed at a total cost of
approximately $140 million. Under a support agreement relating to the
Company's participation in the facilities, the Company is obligated to
pay its 4.56% of Phase I Hydro-Quebec capital costs over a 20 year
recovery period through and including 2006. The Company also
participated in the construction of Phase II Hydro-Quebec transmission
facilities which began operation in November 1990. This service
increased the maximum capacity of the Hydro-Quebec 450 kV DC line from
690 mW to 2000 mW and extended the Phase I line from Comerford, New
Hampshire to Sandy Pond, Massachusetts. The Company uses this
transmission path to deliver a portion of the Company's long-term
Hydro-Quebec firm power contract. The project cost approximately
$487 million. Under a similar support agreement, the Company is
obligated to pay its 5.132% share of Phase II Hydro-Quebec capital
costs over a 25-year recovery period through and including 2015. Under
the support agreement, the Company is eligible for savings associated
with certain energy transactions by NEPOOL, which will offset the
Company's support cost obligations.

CONSERVATION AND LOAD MANAGEMENT

The primary purpose of Conservation and Load Management programs
is to offset the need for long-term power supply and delivery resources
that are more expensive to purchase or develop than customer-efficiency
programs.

The Company provides information to customers to help them use
electricity more efficiently, first by ensuring that the customers are
on the correct rate and have incorporated efficiency and conservation
measures; secondly, by continually evaluating new energy management
systems and other technologies to identify and develop programs to
address new market opportunities and the competitive strengths of
electricity. However, during 1999, the Company worked with legislators
and the PSB to transfer energy efficiency programs from the utilities
to an independent agent of state government. The PSB has approved the
creation of a state-wide Energy Efficiency Utility which it is expected
to begin operating in the first half of 2000.

DIVERSIFICATION

See PART II, Items 7 and 8 herein for information regarding the
Company's diversification activities.

The Company is continually assessing additional diversification
opportunities. Any new investments will be financed primarily through
a combination of debt and equity.

EMPLOYEE INFORMATION

A Local Union No. 300 affiliated with the International
Brotherhood of Electrical Workers represents operating and maintenance
employees of the Company and its wholly owned subsidiaries. At
December 31, 1999 the Company and its wholly owned subsidiaries
employed 542 persons, of which 217 are represented by the union. On
December 30, 1998, the Company and its employees represented by the
union agreed to a three-year contract, which expires on December 31,
2001. The new contract provides for a general wage increase of 2.6%
effective January 1, 1999, January 2, 2000 and December 31, 2000.
Under the terms of the new agreement, Company's employees represented
by the union will contribute weekly pre-tax premiums for medical
coverage of eight, nine and ten dollars effective July 1, 1999,
January 1, 2000 and January 1, 2001, respectively.

SEASONAL NATURE OF BUSINESS

The Company experiences its heaviest loads in the colder months of
the year. Winter recreational activities, longer hours of darkness and
heating loads from cold weather usually cause the Company's peak of
electric mWh sales to occur in January or late December. For
additional information regarding the seasonal nature of business see
PART II, Item 8 herein.

OFFICERS

The following sets forth the Executive Officers of the Company.
There are no family relationships among the executive officers.
Officers are normally elected annually.

Executive Officers of the Registrant:

<TABLE>
<CAPTION>
Name and Age Office Officer Since
<S> <C> <C>
Robert H. Young, 52 President and Chief 1987
Executive Officer

Francis J. Boyle, 54 Senior Vice President, 1995
Chief Financial Officer
and Treasurer

Kent R. Brown, 54 Senior Vice President- 1996
Engineering and Operations

William J. Deehan, 47 Vice President-Regulatory 1991
Affairs and Strategic Analysis

Joan F. Gamble, 42 Assistant Vice President, 1998
Human Resources and Strategic
Planning

Joseph M. Kraus, 44 Senior Vice President, 1987
Secretary and General Counsel

James M. Pennington, 44 Vice President, Controller and 1993
Principal Accounting Officer

Robert E. Rogan, 40 Vice President, Public Affairs 1998

Douglas D. Sinclair, 51 Vice President and General 1997
Manager for Business Development

Carl G. Zeller, Jr., 46 Assistant Vice President and 1999
Servco Manager

L. Douglas Barba, 51 Executive Vice President and 1992
General Manager - Catamount
Energy Corporation

</TABLE>

Mr. Young joined the Company in 1987. He was elected Senior Vice
President - Finance and Administration in 1988. He previously served
as Senior Vice President and Chief Operating Officer commencing in 1993
and Director, President and Chief Executive Officer commencing in 1995.

Mr. Boyle joined the Company in October 1995. Prior to being
elected to his present position in 1997, Mr. Boyle served as Vice
President - Finance and Administration and Chief Financial Officer.
Mr. Boyle served as Chief Financial Officer of Westmoreland Coal
Company ("Westmoreland") in Philadelphia, Pennsylvania from 1993 to
1995. In November 1994, Westmoreland and several of its subsidiaries
commenced Chapter 11 proceedings to confirm a so-called "prepackaged"
plan of reorganization under which the court was asked to approve a
sale of assets, the proceeds of which were to be used to satisfy in
full certain maturing obligations of Westmoreland. In December 1994,
Westmoreland's plan of reorganization was confirmed, the asset sale was
consummated, the obligations in question were paid, and Westmoreland
emerged from Bankruptcy. On December 23, 1996, Westmoreland and four
of its subsidiaries commenced Chapter 11 proceedings. The Chapter 11
proceedings were precipitated by large liabilities Westmoreland and
four of its subsidiaries have to retiree medical benefit plans for the
benefit of retired mine workers.

Mr. Brown joined the Company in September 1996. Prior to being
elected to his present position in 1997, he served as Vice
President - Engineering and Operations commencing in 1996. From 1992
to 1995 he served as Chairman, President and Chief Executive Officer of
Kansas Gas and Electric Company.

Mr. Deehan joined the Company in 1985. Prior to being elected to
his present position in 1996, he served as Assistant Vice
President - Rates and Economic Analysis commencing in 1991.

Ms. Gamble joined the Company in 1989. Prior to being elected to
her present position in May 1998, she was Director of Marketing
research & Planning from 1989 to 1996; Director of Strategic and Policy
Planning from 1996 to September 1997 and Director of Human Resources
and Strategic Planning from September 1997 to May 1998.

Mr. Kraus joined the Company in 1981. Prior to being elected to
his present position in 1999, he served as Vice President, Corporate
Secretary and General Counsel commencing in 1996 and Corporate
Secretary and General Counsel commencing in 1994.

Mr. Pennington joined the Company in 1989. Prior to being elected
to his present position in 1992, Mr. Pennington was designated Acting
Controller effective July 19, 1992, and was elected Controller and
named Principal Accounting Officer in 1993.

Mr. Rogan joined the Company in 1998 as Vice President, Public
Affairs. Prior to joining the Company, he served as Deputy Chief of
Staff for the Governor of Vermont from 1994 to 1998. He served as
Director of External Affairs for the Agency of Health Care
Administration in Florida from 1992 to August 1994.

Mr. Sinclair joined the Company April 1997 as Vice President and
General Manager for Business Development. Prior to joining the
Company, from 1994 to 1996 he served as President and Chief Executive
Officer at Noma International. In 1991 he joined Novatel
Communications, Ltd. As Chief Financial Officer and was President and
Chief Executive Officer of Novatel Carmcom, Inc. From 1992 to 1994.

Mr. Zeller joined the Company in 1998. Prior to being elected to
his present position in 1999, he was (and remains) Director of
Information Systems and Technology. From 1989 to 1998, he was a Senior
Associate at Booz, Allen & Hamilton, Inc., a technology and management
consulting firm.

Mr. Barba joined Catamount Energy Corporation, a subsidiary of
Catamount Resources Corporation (a wholly owned subsidiary of the
Company), in August 1992. Prior to being elected to his present
position in 1999, he served as Senior Vice President and General
Manager in 1992.

The term of each officer is for one year or until a successor is
elected.

Item 2. Properties.

The Company. The Company's properties are operated as a single
system which is interconnected by transmission lines of VELCO, NEP and
PSNH. The Company owns and operates 23 small generating stations with
a total current nameplate capability of 70,070 kW, has a 1.78%
joint-ownership interest in an oil generating plant in Maine, has a 20%
joint-ownership interest in a wood, gas and oil-fired generating plant
in Vermont, has a 1.73% joint-ownership interest in a nuclear
generating plant in Connecticut and has a 47.35% joint-ownership
interest in a transmission interconnection with Hydro-Quebec in
Vermont.

The electric transmission and distribution systems of the Company
include about 614 miles of overhead transmission lines, about 7,371
miles of overhead distribution lines and about 273 miles of underground
distribution lines which are located in Vermont except for about 23
miles of transmission lines which are located in New Hampshire and
about two miles of transmission lines which are located in New York.

Connecticut Valley. Connecticut Valley's electric properties
consist of two principal systems in New Hampshire which are not
interconnected with each other but each of which is connected directly
with facilities of the Company.

The electric systems of Connecticut Valley include about two miles
of transmission lines and about 433 miles of overhead distribution
lines and about 12 miles of underground distribution lines.

All the principal plants and important units of the Company and
its subsidiaries are held in fee. Transmission and distribution
facilities which are not located in or over public highways are, with
minor exceptions, located either on land owned in fee or pursuant to
easements substantially all of which 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 of state or municipal authorities.

VELCO. VELCO's properties consist of about 483 miles of high
voltage overhead transmission lines and associated substations. The
lines connect on the west at the Vermont-New York state line with the
lines of Niagara Mohawk Power Corporation near Whitehall, New York, and
Bennington, Vermont and with the submarine cable of NYPA near
Plattsburg, New York; on the south and east with lines of New England
Power Company and PSNH; on the south with the facilities of Vermont
Yankee; and on the north with lines of Hydro-Quebec through a converter
station and tie line jointly owned by the Company and several other
Vermont utilities.

VETCO. VETCO has approximately 52 miles of high voltage DC
transmission line connecting at the Quebec-Vermont border in the Town
of Norton, Vermont with the transmission line of Hydro-Quebec and
connecting at the Vermont-New Hampshire border near New England Power
Company's Moore hydro-electric generating station with the transmission
line of New England Electric Transmission Corporation, a subsidiary of
New England Electric System.

Item 3. Legal Proceedings.

On August 7, 1997, the Company and eight other non-operating
owners of Unit #3 filed a demand for arbitration with Connecticut Light
and Power Company and Western Massachusetts Electric Company, both NU
affiliates, and lawsuits against NU and its trustees. The arbitration
and lawsuits seek to recover costs associated with replacement power,
operation and maintenance costs and other costs resulting from the
shutdown of Unit #3. The non-operating owners claim that NU and two of
its wholly owned subsidiaries failed to comply with NRC's regulations,
failed to operate the facility in accordance with good operating
practice and attempted to conceal their activities from the
non-operating owners and the NRC. A mediator has been hired in an
attempt to settle prior arbitration and the lawsuit.

On October 27, 1999, NU and NEP, disclosed that NU had reached an
agreement with NEP and MEC, two of the non-operating minority joint
owners, to settle their claims in the arbitration and lawsuits. The
settlement involves payment of fixed and contingent amounts to NEP and
MEC and the inclusion of their Unit #3 interests in NU's auction of the
plant. In addition, on January 28, 2000 Central Maine Power Company
("CMP"), also one of the non-operating minority joint owners, disclosed
that NU and CMP had reached an agreement to settle CMP's claims in the
arbitration and litigation. However, no terms of the agreement have
been disclosed by CMP. The other non-operating minority joint owners,
including the Company, remain active in the arbitration and lawsuits
and in seeking to settle our claims against NU.

Except as otherwise described under Management's Discussion and
Analysis of Financial Condition and Results of Operations, Item 7,
there are no other material pending legal proceedings, other than
ordinary routine litigation incidental to the business, to which the
Company or any of its subsidiaries is a party or to which any of their
property is subject.

Item 4. Submission of Matters to a Vote of Security Holders.

There were no matters submitted to security holders during the
fourth quarter of 1999.

PART II

Item 5. Market for Registrant's Common
Equity and Related Stockholder Matters.

(a) The Company's common stock is traded on the New York Stock
Exchange ("NYSE") under the trading symbol CV. Newspaper listings of
stock transactions use the abbreviation CVtPS or CentlVtPS and the
Internet trading symbol is CV.

The table below shows the high and low sales price of the
Company's common stock, as reported on the NYSE composite tape by The
Wall Street Journal, for each quarterly period during the last two
years as follows:
<TABLE>
<CAPTION>
Market Price
High Low
1999
<S> <C> <C>
First quarter.............. $ 13 $ 9 7/8
Second quarter............. 13 9 9/16
Third quarter.............. 14 7/16 12 3/8
Fourth quarter............. 13 7/8 10 3/16

1998
First quarter.............. $ 15 7/16 $ 13 1/8
Second quarter............. 15 1/4 14 5/16
Third quarter.............. 14 15/16 9 3/4
Fourth quarter............. 11 1/2 9 3/4
</TABLE>

(b) As of December 31, 1999, there were 10,862 holders of the
Company's Common Stock, $6 par value.

(c) Common stock dividends have been declared quarterly. Cash
dividends of $.22 per share were paid for all quarters of 1998 and
1999.

So long as any Senior Preferred Stock or Second Preferred Stock is
outstanding, except as otherwise authorized by vote of two-thirds of
each such class, if the Common Stock Equity (as defined) is, or by the
declaration of any dividend will be, less than 20% of Total
Capitalization (as defined), dividends on Common Stock (including all
distributions thereon and acquisitions thereof), other than dividends
payable in Common Stock, during the year ending on the date of such
dividend declaration, shall be limited to 50% of the Net Income
Available for Dividends on Common Stock (as defined) for that year; and
if the Common Stock Equity is, or by the declaration of any dividend
will be, from 20% to 25% of Total Capitalization, such dividends on
Common Stock during the year ending on the date of such dividend
declaration shall be limited to 75% of the Net Income Available for
Dividends on Common Stock for that year. The defined terms identified
above are used herein in the sense as defined in subdivision 8A of the
Company's Articles of Association; such definitions are based upon the
unconsolidated financial statements of the Company. As of December 31,
1999, the Common Stock Equity of the unconsolidated Company was 50.1%
of total capitalization.

For additional information regarding dividend payment level and
dividend restrictions see Item 8 herein.

<PAGE>
<TABLE>
<CAPTION>
Item 6. Selected Financial Data.
(Dollars in thousands, except per share amounts)

1999 1998 1997 1996 1995
<S> <C> <C> <C> <C> <C>
For the year
- - - - - - - - - - - - - - - - - ------------
Operating revenues $419,815 $303,835 $304,732 $290,801 $288,277
Net income before extraordinary charge $ 16,584 $ 3,983 $ 17,151 $ 19,442 $ 19,851
Extraordinary charge net of taxes $ - $ - $ 811 $ - $ -
Net income $ 16,584 $ 3,983 $ 16,340 $ 19,442 $ 19,851
Earnings available for common stock $ 14,722 $ 2,038 $ 14,312 $ 17,414 $ 17,823
Consolidated return on average
common stock equity 7.9% 1.1% 7.5% 9.4% 10.0%
Earnings per basic and diluted share
of common stock before extraordinary
charge $1.28 $.18 $1.32 $1.51 $1.53
Earnings per basic and diluted share of
common stock $1.28 $.18 $1.25 $1.51 $1.53
Cash dividends paid per share of
common stock $.88 $.88 $.88 $.84 $.80
Book value per share of common stock $16.05 $15.63 $16.38 $16.19 $15.51
Net cash provided by operating
activities $ 31,232 $ 21,743 $ 41,974 $ 43,007 $ 42,583
Dividends paid $ 11,950 $ 12,006 $ 12,630 $ 11,728 $ 11,350
Construction and plant expenditures $ 13,231 $ 16,046 $ 13,841 $ 18,952 $ 21,337
Conservation and load management
expenditures $ 2,440 $ 2,208 $ 1,837 $ 1,589 $ 3,899

At end of year
- - - - - - - - - - - - - - - - - --------------
Long-term debt $155,251 $ 90,077 $ 93,099 $117,374 $119,142
Capital lease obligations $ 15,060 $ 16,141 $ 17,223 $ 18,304 $ 19,385
Redeemable preferred stock $ 17,000 $ 18,000 $ 19,000 $ 20,000 $ 20,000
Total capitalization
(excluding current portion
of debt) $379,386 $311,454 $324,499 $350,201 $346,341
Total assets $563,959 $530,282 $531,940 $502,968 $489,213

</TABLE>

Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.

Earnings Overview

The Company's 1999 net income was $16.6 million or $1.28 per share
of common stock, which equates to a 7.9% return on average common
equity. Net income and earnings per share of common stock for 1999
compares to $4.0 million and $.18 in 1998, and $16.3 million and $1.25
in 1997. The return on average common equity was 1.1% for 1998 and
7.5% for 1997.

Improved 1999 earnings versus 1998 resulted primarily from higher
retail revenues associated with the positive impact of a 4.7% temporary
Vermont rate increase ($7.1 million after-tax, or $.61 per share of
common stock) as well as a 2.0% increase in retail mWh sales ($2.6
million after-tax, or $.23 per share of common stock). In addition,
net income and earnings per share of common stock for 1999 reflect the
positive effect of reversing $4.3 million after-tax, or $.38 per share
of common stock, resulting from disallowed Hydro-Quebec purchased power
costs in the same amount accrued during the fourth quarter of 1998, and
the reversal of 1998 charges during 1999 of $4.3 million after-tax, or
$.38 per share of common stock. This positive effect was offset by the
recognition of 2000 disallowed Hydro-Quebec power costs of about $1.7
million after-tax, or $.15 per share of common stock, in the fourth
quarter of 1999. Net income and earnings per share of common stock
were also affected by non-utility losses of $2.5 million after-tax, or
$.22 per share of common stock, related to SmartEnergy Services, Inc.
("SmartEnergy") proportionate share in Home Service Solutions LLC
(d.b.a. The Home Service Store) ("HSS"), and Catamount Energy
Corporation ("Catamount"), and higher operating and maintenance costs
of $3.1 million after-tax, or $.28 per share of common stock, caused by
two major storms in 1999 as well as increased regulatory and legal
costs, partially offset by the favorable effect of Accounting Orders
for the deferral of certain legal and regulatory costs of $1.3 million,
or $.12 per share of common stock. Higher interest costs of $1.1
million, or $.10 per share of common stock, due to the sale of Second
Mortgage Bonds and increases in average outstanding short-term debt.
Lower power costs of $1.7 million after-tax, or $.14 per share of
common stock, principally related to better performance at Unit #3
(Unit #3 was off-line during the first half of 1998) and Vermont Yankee
Nuclear Power Corporation ("Vermont Yankee") plant due to the extended
refueling outage in 1998, partially offset by higher power costs
related to the Hydro-Quebec contract.

For 1998 compared to 1997, net income and earnings per share of
common stock for the Company's utility business reflects the negative
impact of increased power costs under the Hydro-Quebec contract of $5.0
million after-tax, or $.44 per share of common stock, increased other
power costs of $1.7 million after-tax, or $.15 per share of common
stock, related to the longer than expected refueling outage at the
Vermont Yankee Nuclear Power plant, higher operating and maintenance
costs of $2.1 million after-tax, or $.18 per share of common stock
caused by increased legal and regulatory costs as well as costs
associated with the ice storm in January 1998. During April 1998 the
Company agreed to toll the statutory period of time in which the
Vermont Public Service Board ("PSB") must act on its pending 6.6% rate
increase request filed in September 1997. At the same time, the
Company asked the Vermont Supreme Court ("VSC") to review the PSB's
denial of the Company's claim that the PSB is precluded from again
trying the Company on certain Hydro-Quebec contract and demand side
management decisions. The appeal and associated stay of the rate case
significantly delayed the date that new rates would have otherwise
taken effect. As a result, the Company's earnings for 1998 were
adversely affected. Second, because of the October 27, 1998 retail
rate increase settlement discussed below and in Note 13 to the
Consolidated Financial Statements, net income and earnings per share of
common stock for 1998 include the negative impact of an after-tax
disallowance of $4.3 million, or $.38 per share of common stock for the
Company's purchased power costs under the Hydro-Quebec Contract.

Also, for 1998, net income and earnings per share of common stock
for the Company's utility business reflects the net effect at
Connecticut Valley of after-tax charges taken during the fourth quarter
of 1998 of $3.7 million, or $.32 per share of common stock, offset by
the reversal of 1997 after-tax charges during the first quarter of 1998
of $4.5 million, or $.39 per share of common stock. These charges and
reversal of charges are discussed below and in Note 13 to the
Consolidated Financial Statements.

On June 12, 1998, the Company filed with the PSB a request for a
10.7% rate increase ($24.7 million of annualized revenues) effective
March 1, 1999. On October 27, 1998, the Company reached an agreement
with the Vermont Department of Public Service ("DPS") regarding this
rate increase request.

The agreement, which was approved by the PSB on December 11, 1998,
provides for a temporary rate increase in the Company's Vermont retail
rates of 4.7% or $10.9 million on an annualized basis beginning with
service rendered January 1, 1999 and sets the Company's authorized
return on common equity in its Vermont retail business at 11%. The
rate increase is temporary insofar as it is subject to adjustment upon
future resolution of the Hydro-Quebec Contract issues presently before
the VSC discussed in Note 13 to the Consolidated Financial Statements.

The Company filed for a 6.6% or $15.4 million general rate
increase on September 22, 1997 to become effective June 6, 1998, which
is now stayed pending a review by the VSC as more fully discussed in
Note 13 to the Consolidated Financial Statements.

Results of Operations.

The major elements of the Consolidated Statement of Income are
discussed below.

Operating revenues and megawatt-hour ("mWh") sales - A summary of
operating revenues and mWh sales for 1999, 1998 and 1997 is set forth
below:
<TABLE>
<CAPTION>
mWh Sales Revenues (000's)
1999 1998 1997 1999 1998 1997
<S> <C> <C> <C> <C> <C> <C>
Residential 948,756 930,666 945,199 $123,302 $115,911 $116,314
Commercial 943,141 937,547 916,311 109,440 103,221 104,460
Industrial 442,308 418,778 427,764 36,823 33,617 34,206
Other retail 6,235 7,123 7,138 1,787 1,943 1,937
--------- --------- --------- -------- -------- -------
Total retail sales 2,340,440 2,294,114 2,296,412 271,352 254,692 256,917
========= ========= ========= ======== ======== =======
Resale sales:
Firm 2,349 2,284 1,051 160 94 46
Entitlement 356,197 319,703 378,273 20,875 19,370 18,925
Alliance 2,986,682 357,400 - 100,116 11,266 -
Other 869,857 651,235 827,818 22,121 15,595 22,265
--------- --------- --------- -------- -------- --------
Total resale sales 4,215,085 1,330,622 1,207,142 143,272 46,325 41,236
========= ========= ========= ======== ======== ========
Other revenues - - - 5,191 2,818 6,579
--------- --------- --------- -------- -------- --------
Total 6,555,525 3,624,736 3,503,554 $419,815 $303,835 $304,732
========= ========= ========= ======== ======== ========
</TABLE>

Year-to-year fluctuations in total retail mWh sales are primarily
affected by customer growth, C&LM programs, as well as relative prices of
alternate energy sources, weather patterns and conservation induced by price
changes and income elasticity responses of customers. Compared to 1998,
retail mWh sales for 1999 increased 46,326 mWh, or 2.0% and related revenues
increased $16.7 million, or 6.5% compared to 1998. The revenue increase was
primarily attributable to the 4.7% temporary Vermont retail rate increase
discussed above and the impact of higher mWh sales.

Compared to 1997, retail mWh sales for 1998 decreased 2,298 mWh and
retail revenues decreased $2.2 million, or .9% compared to 1997. The
revenue decrease was primarily attributable to a modified rate design
reflected in bills rendered since April 1, 1997. The modified rate design,
which was revenue neutral on an annual basis, decreased average prices
slightly charged during 1998 from average levels for 1997.

For 1999, entitlement mWh sales increased 11.4% compared to 1998. This
increase resulted primarily from the Vermont Yankee extended refueling
outage in 1998.

Entitlement mWh sales for 1998 decreased 15.5% compared to 1997. The
decrease resulted primarily from the scheduled refueling and maintenance
outage of the Vermont Yankee plant. The outage, which reduced the plant's
1998 output, also reduced mWh sales. However, a portion of the higher costs
of the Company's share of Vermont Yankee's costs associated with the
refueling and maintenance outage was passed on to entitlement customers
resulting in an increase in entitlement revenues of $.4 million, or 2.4%.

For 1999 alliance resale sales increased 2,629,282 mWh and related
revenues increased $88.9 million . This increase results from activity by
the Company through its alliance with Virginia Power in jointly supplying
wholesale power primarily in the Northeast states. In the third quarter of
1999 the Company decided to discontinue this alliance.

Other resale sales increased 218,622 mWh for 1999 and decreased 176,583
mWh for 1998. Related revenues increased $6.5 million for 1999 and
decreased $6.7 million for 1998. These variances reflect current market
conditions in Vermont and New England and the greater availability of low
cost energy in the region. These sales made on a short-term basis include
sales to NEPOOL and other utilities in New England.

Other revenues increased $2.4 million for 1999 compared to 1998
primarily due to refund obligations recorded in the fourth quarter of 1998
by Connecticut Valley as more fully discussed below.

For 1998 compared to 1997 other revenues decreased due to a provision
for rate refunds of $2.7 million related to a Fuel Adjustment Clause ("FAC")
and Purchased Power Cost Adjustment ("PPCA") at Connecticut Valley,
associated with the December 3, 1998 Court of Appeals' decision discussed
below, and revenues of about $.7 million associated with transmission
interconnection agreements in 1997 and lower revenues from pole attachment
rentals.

The table below summarizes the components of increases or decreases in
revenues compared to the prior year (dollars in thousands):
<TABLE>
<CAPTION>
1999 1998
<S> <C> <C>
Revenue increase (decrease) from:
Retail MWh sales $ 4,516 $ (90)
Retail rates 12,144 (2,135)
Changes in firm resale sales 66 48
Changes in entitlement sales 1,505 445
Change in alliance sales 88,850 11,266
Changes in other resale sales 6,526 (6,670)
Changes in other revenues 2,373 (3,761)
-------- -------
Net increase over prior year $115,980 $ (897)
======== =======
</TABLE>

Purchased power - The Company purchases approximately 90% of its power needs
under several contracts of varying duration. Over 30% of its purchases are
from affiliated companies whereby the Company receives its entitlement share
of the output. The Company's purchased power portfolio assures that a
diversified mix of sources and fuel types are available to meet the
Company's long-term load growth while providing short and intermediate term
opportunities to purchase or sell capacity and energy to reduce overall
power costs. A breakdown of the Company's energy sources, excluding sources
related to the Company's alliance with Virginia Power discussed above, is
shown below:
<TABLE>
<CAPTION>
Year Ended December 31
1999 1998 1997
<S> <C> <C> <C>
Nuclear generating companies 34% 37% 36%
Canadian imports 35 31 32
PSNH-coal - 2 9
Company-owned hydro 5 7 5
Jointly owned units 6 3 1
Independent power producers 5 6 6
Other sources 15 14 11
--- --- ---
100% 100% 100%
=== === ===
</TABLE>

The Company maintains a 1.7303% joint-ownership interest in Unit #3 of
the Millstone Nuclear Power Station and owns a 2% equity interest in
Connecticut Yankee. These two plants are operated by Northeast Utilities
("NU"). The Company also maintains joint-ownership interests in Joseph C.
McNeil, a 53 mW wood, gas and oil-fired unit and Wyman #4, a 619 mW
oil-fired unit and owns a 31.3%, 2% and 3.5% equity interest in Vermont
Yankee, Maine Yankee and Yankee Atomic, respectively. The Company's
entitlement percentage for Vermont Yankee is 35%. In addition, the Company
owns 20 hydroelectric generating units with a total nameplate capability of
41.2 mW and two gas-fired and one diesel-peaking units with a combined
nameplate capability of 28.9 mW.

Millstone Unit #3

The Company remains actively involved with the other non-operating
minority joint-owners of Unit #3. This group is engaged in various
activities to monitor and evaluate NU and Northeast Utilities Service Co.'s
efforts relating to Unit #3. On August 7, 1997, the Company and eight other
non-operating owners of Unit #3 filed a demand for arbitration with
Connecticut Light and Power Company and Western Massachusetts Electric
Company, both NU affiliates, and lawsuits against NU and its trustees. The
arbitration and lawsuits seek to recover costs associated with replacement
power, operation and maintenance costs and other costs resulting from the
lengthy outage of Unit #3. The non-operating owners claim that NU and two
of its wholly owned subsidiaries failed to comply with NRC's regulations,
failed to operate the facility in accordance with good operating practice
and attempted to conceal their activities from the non-operating owners and
the NRC.

On September 15, 1999, NU announced that it intends to auction its
nuclear generating plants, including Unit #3. We cannot predict at this
time the effect of such an auction, if it occurs, on the Company or on the
ongoing litigation.

On October 27, 1999, NU and NEP, disclosed that NU had reached an
agreement with NEP and MEC, two of the non-operating minority joint owners,
to settle their claims in the arbitration and lawsuits. The settlement
involves payment of fixed and contingent amounts to NEP and MEC and the
inclusion of their Unit #3 interests in NU's auction of the plant. On
January 28, 2000, Central Maine Power Company ("CMP"), also one of the
non-operating minority joint owners, disclosed that NU and CMP had reached
an agreement to settle CMP's claims in the arbitration and litigation.
However, no terms of the agreement have been disclosed by CMP. The other
non-operating minority joint owners, including the Company, remain active in
the arbitration and lawsuits and in seeking to settle our claims against NU.

Based on the most recent decommissioning estimate in 1997, the
Company's total share of Unit #3 decommissioning costs at December 31, 1999
was $10.7 million. As of December 31, 1999, the Company has funded $4.0
million of these costs.

Vermont Yankee

The Vermont Yankee nuclear power plant, which provides more than
one-third of the Company's power supply, began a refueling outage on October
29, 1999 and returned to service on December 2, 1999. The 1998 refueling
outage (March 21 - June 3) extended 26 days beyond the scheduled 49 days.
Vermont Yankee had no scheduled refueling outage in 1997.

During scheduled nuclear refueling outages, the Company purchases more
costly replacement energy from other sources to satisfy energy needs. In
accordance with current rate-making treatment, the Company defers and
amortizes to expense over their respective fuel cycles the incremental
replacement energy and maintenance costs associated with refueling outages
for the Vermont Yankee nuclear power plant and Unit #3, a jointly owned
nuclear generating unit. During 1999, the Company deferred $2.1 million and
$6.8 million for replacement energy and maintenance costs, respectively.

During 1996, Vermont Yankee initiated a Design Basis Documentation
project expected to be complete by December 31, 2001. This project was
undertaken to incorporate all design documentation into a centralized
system. The objective is to ensure that Vermont Yankee maintains its safety
margins in connection with any plant modifications. The Design Basis
Documentation project will create a set of design basis documents which will
support more efficient systematic problem solving, maintenance, and system
overview. This effort supports the safe, cost effective, long term
operation of the Vermont Yankee Plant. Vermont Yankee received FERC
approval in 1996 to defer these unrecovered study costs and amortize the
costs through billings to Sponsors over the remaining license life of the
Plant. The Company's 35% share of the total cost for this Project is
expected to be between $5.5 million and $6.2 million.

On October 15, 1999 the Company and the other owners of Vermont Yankee
accepted a bid for sale of the plant to AmerGen Energy Co., which is owned
by PECO Energy Company and British Energy. On November 17, 1999, Vermont
Yankee executed an Asset Purchase Agreement with AmerGen Energy Co. The
Agreement is subject to several conditions, including approvals or specific
rulings by various regulatory authorities. As such, execution of the
Agreement does not provide assurance that the sale will occur. This
agreement will also involve the Company entering into a contract to purchase
a portion of the power produced by this plant.

The price to be paid by AmerGen for the plant and property will range
from $10 million to $23.5 million depending on when the sale occurs.
Additionally, Vermont Yankee's current owners will make a one-time payment
of $54.3 million to pre-pay the plant's decommissioning fund at $312.7
million. In return, AmerGen will assume full responsibility for all future
operating costs and the estimated $816.6 million price tag for
decommissioning the plant at the end of its operating license in 2012.

Maine Yankee

On August 6, 1997, the Maine Yankee's nuclear power plant was
prematurely retired from commercial operation. The Company relied on Maine
Yankee for less than 5% of its required system capacity. Future payments
for the closing, decommissioning and recovery of the remaining investment in
Maine Yankee are estimated to be approximately $715.0 million in 1998
dollars including a decommissioning obligation of $344.0 million.

On January 19, 1999, Maine Yankee and the active intervenors filed an
Offer of Settlement with the FERC which the FERC has approved. As a result,
all issues raised in the FERC proceeding, including recovery of anticipated
future payments for closing, decommissioning and recovery of the remaining
investment in Maine Yankee are resolved. Also resolved are the issues raised
by the secondary purchasers, who purchased Maine Yankee power through
agreements with the original owners, by limiting the amounts they will pay
for decommissioning the Maine Yankee plant and by settling other points of
contention affecting individual secondary purchasers. As a result, it is
possible that the Company will not be able to recover approximately $.5
million of these costs.

Connecticut Yankee

On December 4, 1996, the Connecticut Yankee Nuclear power plant was
prematurely retired from commercial operation. The Company relied on
Connecticut Yankee for less than 3.0% of its required system capacity.

On August 31, 1998, a FERC Administrative Law Judge recommended that
the owners of Connecticut Yankee, including the Company, may collect from
customers $350.0 million for decommissioning the Connecticut Yankee Nuclear
Power Plant rather than the $426.7 million requested. The Administrative
Law Judge ruling is subject to approval by the FERC Commissioners. If
approved, it is possible that the Company would not be able to recover
approximately $1.5 million of decommissioning costs through the regulatory
process.

Yankee Atomic

In 1992, the Yankee Atomic nuclear power plant was retired from
commercial operation. The Company relied on Yankee Atomic for less than
1.5% of its system capacity.

Maine Yankee, Connecticut Yankee and Yankee Atomic Decommissioning Costs

Presently, costs billed to the Company by Maine Yankee, Connecticut
Yankee and Yankee Atomic, including a provision for ultimate decommissioning
of the units, are being collected from the Company's customers through
existing retail and wholesale rate tariffs. The Company's share of
remaining costs with respect to Maine Yankee, Connecticut Yankee and Yankee
Atomic's decisions to discontinue operation is estimated to be $12.8
million, $8.4 million and $.9 million, respectively, at December 31, 1999.
These amounts are subject to ongoing review and revisions and are reflected
in the accompanying balance sheet both as regulatory assets and nuclear
dismantling liabilities (current and non-current).

The decision to prematurely retire these nuclear power plants was based
on economic analyses of the costs of operating them compared to the costs of
closing them and incurring replacement power costs over the remaining period
of the plants' operating licenses. The Company believes that based on the
current regulatory process, its proportionate share of Maine Yankee,
Connecticut Yankee and Yankee Atomic decommissioning costs will be recovered
through the regulatory process and, therefore, the ultimate resolution of
the premature retirement of the three plants has not and should not have a
material adverse effect on the Company's earnings or financial condition.

Merrimack Unit #2

Until its termination on April 30, 1998, the Company purchased power
and energy from Merrimack Unit #2 pursuant to a contract dated July 16, 1966
entered into by and between VELCO and PSNH. See Note 14 to the Consolidated
Financial Statements for further details related to the Merrimack Unit #2
contract.

Cogeneration/Independent Power Qualifying Facilities

A number of IPPs using hydroelectric, biomass, and refuse-burning
generation are currently producing energy that the Company is purchasing.
The majority of these purchases are made from a state appointed purchasing
agent who purchases and redistributes the power to all Vermont utilities.
Under these long-term contracts, in 1999 the Company received 193,114 mWh of
which 139,407 mWh is associated with the Vermont Electric Power Producers
and 37,309 mWh with the New Hampshire/Vermont Solid Waste Plant owned by
Wheelabrator Claremont Company, L.P. The Company expects to purchase
approximately 205,821 mWh of independent power output in each year 2000 to
2004. Based on the forecast level of production, the total commitment in
the next five years to purchase power from these independent power
facilities is estimated to be $118.4 million.

As part of the Company's initiative to cut power costs and restructure
Vermont's utility industry, on August 3, 1999, the Company, Green Mountain
Power ("GMP"), Citizens Utilities and all of Vermont's 15 municipal
utilities, filed a petition with the PSB requesting modification of the
contracts between the IPPs and the state appointed purchasing agent. The
petition is based on unique provisions of the existing contracts and PSB
regulations that provide for modifications and alterations that serve the
public interest. The petition outlines seven specific elements that, if
implemented, would reduce the purchase power costs of these contracts.

On September 3, 1999, the PSB responded to the Company's petition by
opening a formal investigation regarding these contracts. Shortly
thereafter, Citizens Utilities, Hardwick Electric Department and the
Burlington Electric Department notified the PSB that they were withdrawing
from the petition but they will participate in the case as a non-moving
parties. In a separate VSC action brought by several IPP's owners, GMP's
full participation in this PSB proceeding was enjoined. That injunction is
now on appeal to the VSC. The Company and the other moving utilities have
requested that the PSB issue an order requiring GMP's full participation in
the PSB proceeding. At the same time, the IPPs have filed a motion seeking
to disqualify the law firm representing the utilities on the grounds of an
alleged conflict of interest. The Company has also filed a related
proceeding in the Washington County Superior Court contending that the PSB
rules pertaining to IPPs, which the utilities have relied upon, in part, in
their petition before the PSB contains a so-called "scrivener's error".

Other

In order to optimize its power mix for baseload, intermediate and
peaking power, the Company engages in purchases and sales with other
electric utilities primarily in New England and with NEPOOL to take
advantage of immediate pricing and other market conditions. The profits
from these transactions are used to reduce purchased power costs. These
purchases are included in Other sources in the Sources of Energy table
above. In addition, in 1999 and 1998, the Company also engaged in marketing
activities with Virginia Power which jointly supply wholesale power
primarily in the Northeast states discussed above. These purchases are
excluded from the sources of energy table above. In the third quarter of
1999, the Company decided to discontinue this alliance.

The net cost components of purchased power and production fuel costs for
the past three years were as follows (dollars in thousands):
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
Units Amount Units Amount Units Amount
----- ------ ----- ------ ----- ------
<S> <C> <C> <C> <C> <C> <C>
Purchased and produced:
Capacity (mW) 845 $ 96,769 613 $104,740 527 $ 99,513

Energy (mWh) 6,369,412 172,691 3,478,860 80,147 3,470,235 71,930
-------- -------- --------

Total purchased power costs 269,460 184,887 171,443
Production fuel (mWh) 402,355 3,165 332,835 1,996 237,064 1,820
-------- -------- --------
Total purchased power and
production fuel costs 272,625 186,883 173,263

Less entitlement and other
resale sales (mWh) 4,212,736 143,112 1,328,338 46,231 1,206,091 41,190
-------- -------- --------
Net purchased power and
production fuel costs $129,513 $140,652 $132,073
======== ======== ========
</TABLE>

For 1999, purchased capacity costs decreased $8.0 million over
1998. This decrease was primarily due to the positive impacts of
recognizing in 1998 disallowed 1999 Hydro-Quebec power costs of $7.4
million (pre-tax) and disallowed 1999 Connecticut Valley's power costs
of $1.6 million (pre-tax). Partially offsetting this decrease is
scheduled cost increases under the Hydro-Quebec contract of $3.0
million and the recognition in 1999 of disallowed first quarter 2000
Hydro-Quebec power costs of $2.9 million (pre-tax), disallowed 2000
Connecticut Valley's power costs of $1.2 million (pre-tax), both
charged in the fourth quarter of 1999, as well as higher costs, in
1998, for the Vermont Yankee extended outage ($1.7 million pre-tax).

For 1998, purchased capacity cost increased $5.2 million over
1997. This increase was the result of a $7.4 million disallowance of
Hydro-Quebec power costs discussed below, $7.2 million of higher costs
primarily associated with the Hydro-Quebec contract, the Vermont Yankee
extended outage and $1.6 million of disallowed power costs at
Connecticut Valley. Offsetting this increase was the impact at
Connecticut Valley totaling $11.0 million associated with the reversal
of a $5.5 million charge-off during 1998 and charge-off during 1997 of
$5.5 million. See Electric Industry Restructuring-New Hampshire
discussed below and Note 13 to the Consolidated Financial Statements
for additional information. Pursuant to a PSB Accounting Order, during
the first half of 1997, the Company reduced capacity costs by $5.8
million related to the Hydro-Quebec agreement for which a payment of
$5.8 million was received from Hydro-Quebec on June 30, 1997.

Energy costs are directly related to the variable prices of oil,
nuclear fuel and coal but, more importantly, to the proportion of the
Company's purchased energy that comes from each of these fuel sources.
Energy purchases increased $92.5 million for 1999 primarily from an 8%,
or $5.8 million increase in the amount of mWh purchased offset by a
$3.8 million decrease in price and $90.4 million associated with
Virginia Power Alliance (2,629,282 mWh). The increase in the Virginia
Power Alliance purchases was offset by increases in alliance resale
sales discussed above.

The increase in energy costs for 1998 resulted from an 11.1% or,
$8.0 million increase in cost per mWh purchased and a $.2 million
increase in the amount of mWh purchased. The price increase resulted
primarily from the higher costs under the Hydro-Quebec power contract,
increased purchases from IPPs, the Vermont Yankee extended outage and
Virginia Power Alliance purchases (357,400 mWh - $10.2 million).

The Company is responsible for paying its entitlement percentage
of decommissioning costs for Vermont Yankee, Connecticut Yankee, Maine
Yankee and Yankee Atomic as well as its joint-ownership percentage of
decommissioning costs for Unit #3. For additional information see
Notes 2 and 14 to the Consolidated Financial Statements.

The staff of the Securities and Exchange Commission has questioned
certain current accounting practices of the electric utility industry,
including the Company, regarding the recognition, measurement and
classification of decommissioning costs for nuclear generating stations
in financial statements of electric utilities. In response to these
questions, the Financial Accounting Standards Board has agreed to
review the industry-wide accounting for nuclear decommissioning costs.
If current electric utility industry accounting practices for such
decommissioning costs are changed, it is possible that annual expense
provisions for decommissioning costs could increase, the total
estimated costs for decommissioning could be recorded as a liability,
and income from external decommissioning trusts could be reported as
investment income instead of a reduction to decommissioning expense.
The Company does not believe that such changes, if required, would have
an adverse effect on results of operations due to its ability to
recover decommissioning costs through the regulatory process. See
Liquidity and Capital Resources - Competition, for related information.

Primarily due to increased generation by the Company's
joint-ownership units, production fuel costs increased for 1999
compared to 1998.

Based on present commitments and contracts, the Company expects
that net purchased power and production fuel costs will be
approximately $137.7 million, $144.5 million and $145.6 million for the
period 2000 through 2002.

Other operation expenses - The increase in other operation expenses of
approximately $2.9 million and $3.2 million for 1999 and 1998,
respectively, resulted primarily from increased regulatory and legal
costs as well as increased conservation and load management costs. The
1999 increase was partially offset by the favorable effect of
Accounting Orders for the deferral of certain legal and regulatory
costs of $2.2 million. See Note 14 to the Consolidated Financial
Statements for related information.

Maintenance expenses - The increase in maintenance expenses of $2.0
million for 1999 is primarily due to higher costs related to two major
storms in 1999 as well as increased costs related to Unit #3.

For 1998 Maintenance expenses associated with the Company's
joint- ownership interest in Unit #3 decreased compared to 1997.
However, this decrease was offset by an increase in maintenance
expenses associated with the Company's tree trimming program and
expenses attributable to a severe ice storm in January 1998.

Income taxes - Federal and state income taxes fluctuate with the level
of pre-tax earnings in relation to permanent differences. For 1999
these taxes increased as a result of an increase in pre-tax earnings
and no change in permanent differences for the period. Income taxes
decreased for 1998 as a result of lower pre-tax earnings and no change
in permanent differences for the period.

Other income and deductions - Other income and deductions decreased for
1999 and 1998. The 1999 decrease was primarily due to lower equity
income from non-utility subsidiary companies primarily related to
SmartEnergy's proportionate share in HSS. The 1998 decrease resulted
from gains of $5.0 million from non-recurring asset sales in 1997.

Interest on long-term debt - In July 1999, the Company sold $75.0
million aggregate principal amount of 8 1/8% Second Mortgage Bonds due
2004. Accordingly, interest on long-term debt increased for 1999.
This increase was partially offset by the retirement of long-term debt
in December 1998.

Other interest expense - Other interest expense increased for 1999 and
1998 due to increases in average outstanding short-term debt.

Extraordinary credit - As a result of legal and regulatory actions
associated with Connecticut Valley, the Company, in 1997, recorded an
extraordinary charge of $.8 million. See Electric Industry
Restructuring-New Hampshire below.

Cash Dividends Declared - For 1997 common dividends declared included
an early declaration made in December 1997 for the quarterly dividend
paid on February 13, 1998.

Liquidity and Capital Resources

The Company's liquidity is primarily affected by the level of cash
generated from operations and the funding requirements of its ongoing
construction and C&LM programs. Net cash provided by operating
activities generated $31.2 million in 1999, $21.7 million in 1998 and
$42.0 million in 1997.

The Company ended 1999 with cash and cash equivalents of
$35.5 million, an increase of $25.4 million from the beginning of the
year. The increase in cash for 1999 was the result of $31.2 million
provided by operating activities, $29.9 million used for investing
activities and $24.1 million provided by financing activities.

Operating Activities - Net income, depreciation and deferred income
taxes and investment tax credits provided $35.5 million. $4.3 million
was used for fluctuations in working capital and other operating
activities.

Investing Activities - Construction and plant expenditures consumed
$13.2 million while $16.8 million was used for C&LM programs and
non-utility investments. $.1 million was provided by other investing
activities.

Financing Activities - Dividends paid on common stock were
$10.1 million, while preferred stock dividends were $1.8 million.
Retirement of long-term debt and retirement of preferred stock required
$3.2 million and $1.0 million, respectively, and reduction in capital
lease obligations required $1.1 million. Short-term obligations
required $40.6 million and issuance of long-term debt provided $81.9
million.

Excluding allowance for funds used during construction,
construction expenditures are estimated at $17.7 million, $18.1 million
and $18.8 million for the years 2000 through 2002, respectively.

The level of short-term borrowings fluctuates based on seasonal
corporate needs, the timing of long-term financings and market
conditions.

On July 30, 1999 the Company sold $75.0 million aggregate
principal amount of 8 1/8% Second Mortgage Bonds due 2004 at a price of
99.915% in accordance with Securities and Exchange Commission Rule
144A. The net proceeds of the offering were used to repay $15.0
million of outstanding loans under the Company's revolving credit
facility and are expected to be used for other general corporate
purposes relative to the Company's utility business. In addition, the
Company canceled its $40.0 million revolving credit facility. The
bonds were registered under the Securities Act of 1933 on November 15,
1999.

The Company has an aggregate of $16.9 million of letters of credit
with termination dates of May 31, 2000. In addition, the Company had
a $12.0 million accounts receivable facility which was repaid by the
Company in November 1999.

On March 12, 1999, Connecticut Valley was notified by Citizens
Bank of New Hampshire ("Bank"), that it would exercise appropriate
remedies in connection with the violation of financial covenants
associated with the $3.75 million loan agreement with the Bank unless
the violation was cured by April 11, 1999. To avoid default of this
loan agreement, on April 6, 1999, pursuant to an agreement reached on
March 26, 1999, the Company purchased from the Bank the $3.75 million
note.

The Company, through a common stock repurchase program initiated
in 1994 and subsequently suspended in order to preserve capital for use
in industry restructuring and other business purposes, purchased
362,447 shares of its common stock in open market transactions during
1995, 1996 and 1997 at an average price of $13.04 per share. These
transactions, net of 43,404 shares sold in connection with the
Company's stock option plans, are recorded as treasury stock, at cost,
in the Company's Consolidated Balance Sheet.

The Company's capital structure ratios (including amounts of
long-term debt due within one year) for the past three years were as
follows:
<TABLE>
<CAPTION>
December 31
1999 1998 1997
<S> <C> <C> <C>
Common stock equity 47% 56% 54%
Preferred stock 6 8 8
Long-term debt 43 31 33
Capital lease obligations 4 5 5
--- --- ---
100% 100% 100%
=== === ===
</TABLE>

On February 2, 1999, Standard & Poor's Corporation ("Standard &
Poor's") lowered its corporate credit rating on the Company to
triple-'B'-minus from triple-'B', the senior secured rating to
triple-'B'-plus from single-'A'-minus, and the preferred stock rating
to double-'B'-plus from triple-'B'-minus. In addition, the ratings
were also placed on CreditWatch with negative implications. On
February 17, 1999, Standard & Poor's rating on the Company's preferred
stock was automatically reduced to double-'B'- from double -'B'- plus
in response to a policy change in the way Standard & Poor's rates
preferred stock.

Standard & Poor's stated "the CreditWatch listing reflects the
potentially adverse impact of pending legal and regulatory decisions
that could seriously weaken the Company's credit profile. The
downgrades reflect increased business risk and weakened financial
measures as a result of recent regulatory decisions in Vermont and New
Hampshire and an adverse ruling by the United States First Circuit
Court of Appeals."

Standard & Poor's also said "Resolution of the CreditWatch listing
will depend on the outcome of the pending Federal Energy Regulatory
Commission case and other legal proceedings at State and Federal
levels. Adequate rate relief and successful mitigation of high power
costs through contract renegotiations or other methods are essential to
stabilizing the ratings."

On July 16, 1999, Standard & Poor's assigned its triple-'B'- minus
rating to the Company's then proposed $75.0 million second mortgage
bonds. Concurrently, the bonds were placed on CreditWatch with
negative implications.

Standard & Poor's said "the second mortgage bonds are rated the
same as the Company's corporate credit rating, and not notched up,
because Standard & Poor's projects that the value of the Company's
collateral will not substantially exceed the maximum combined amount of
first and second mortgage bonds that could be outstanding under the
terms of their respective indentures in a default scenario."

On February 17, 1999, Duff & Phelps Credit Rating Co.("Duff &
Phelps") placed the credit ratings of the Company on Rating Watch-Down
due to the high level of regulatory and public policy uncertainty in
Vermont and the recent unfavorable ruling by the United States Court of
Appeals relating to Connecticut Valley, the Company's wholly owned New
Hampshire subsidiary.

Duff & Phelps stated "recent negative rulings by the PSB regarding
purchased power costs and the high level of uncertainty with public
policy toward electric utilities in Vermont adds risk to the Company's
financial profile going forward".

On July 16, 1999 Duff & Phelps lowered the preferred stock rating
to 'BB+' (Double-B-plus) from 'BBB-' (Triple-B-minus) to reflect the
new $75.0 million issuance of second mortgage bonds. Duff & Phelps
credit ratings remain at 'BBB' (Triple-B) for first mortgage bonds.

Current credit ratings of the Company's securities by Standard &
Poor's and Duff & Phelps are as follows:

Standard Duff &
& Poor's(1) Phelps(2)
-------- ------
Corporate Credit Rating BBB- N/A
First Mortgage Bonds BBB+ BBB
Second Mortgage Bonds BBB- BBB-
Preferred Stock BB BB+

(1) All Standard & Poor's ratings are placed on "CreditWatch
with negative implications".
(2) All Duff & Phelps ratings are placed on "Rating
Watch Down"

On November 12, 1998, Catamount, replaced its $8.0 million credit
facility with a $25.0 million revolving credit/term loan facility
maturing November 2006 which provides for up to $25.0 million in
revolving credit loans and letters of credit. This facility has a
security interest in Catamount's assets. Catamount currently has a
$1.2 million letter of credit outstanding to support certain of its
obligations in connection with a debt service requirement in the
Appomattox Cogeneration project. In addition, a letter of credit for
$11.0 million is outstanding in support of construction and equity
commitments for its Gauley River Power project.

SmartEnergy Water Heating Services, Inc., a wholly owned
subsidiary of SmartEnergy, has a secured seven-year term loan with Bank
of New Hampshire with an outstanding balance of $1.3 million at
December 31, 1999. The interest rate is fixed at 9.25%.

Financial obligations of the Company's subsidiaries are
non-recourse to the Company.

The Company cannot assure that its business will generate
sufficient cash flow from operations or that future borrowings will be
available to the Company in an amount sufficient to enable the Company
to pay its indebtedness, including the $75.0 million second mortgage
bonds, when due or to fund its other liquidity needs. The Company's
ability to repay its indebtedness is, to a certain extent, subject to
general economic, financial, competitive, legislative, regulatory,
weather and other factors that are beyond its control. The type, timing
and terms of future financing that the Company may need will be
dependent upon its cash needs, the availability of refinancing sources
and the prevailing conditions in the financial markets. The Company
cannot guarantee that financing sources will be available to the
Company at any given time or that the terms of such sources will be
favorable.

Diversification

Catamount Resources Corporation was formed for the purpose of
holding the Company's subsidiaries that invest in non-regulated
business opportunities. Catamount a subsidiary of Catamount Resources
Corporation, invests in energy generation projects in North America and
Western Europe. Through its wholly owned subsidiaries, Catamount has
interests in seven operating independent power projects located in
Glenns Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont;
Thetford, England; Hopewell, Virginia; and Fort Dunlop, England. In
addition, Catamount has interests in a project under construction in
Summersville, West Virginia. In November 1999 Catamount created a new
subsidiary, Catamount Investment Company LLC, which will provide
additional capital for investment in new generation projects. Catamount
has partnered with CIT Group, a major equipment finance company, and
Dana Commercial Credit Corporation, the finance subsidiary of Dana
Corporation. Capital commitments from these two joint venture partners
are $60.0 million, to be invested over the next four years.
Catamount's after-tax earnings were $2.1 million, $3.3 million and $4.1
million for 1999, 1998 and 1997, respectively.

SmartEnergy also a subsidiary of Catamount Resources Corporation
invests in unregulated energy and service related businesses.
SmartEnergy also has a 70% ownership interest in HSS. Overall,
SmartEnergy incurred net losses of $2.9 million, $1.5 million and $.7
million for 1999, 1998 and 1997, respectively. HSS establishes a
network of affiliate contractors who perform home maintenance repair
and improvements via membership. Although SmartEnergy owns a 70%
interest in HSS, this investment is accounted for using the equity
method on the basis that financing plans will be completed in early
2000 which will have the effect of diluting SmartEnergy's ownership to
a less than 50% level. HSS began operations in 1999 and is subject to
risks and challenges similar a company in the early stage of
development. HSS' pre-tax loss for 1999 was $7.1 million, of which
SmartEnergy's share is $5.3 million.

HSS began a test rollout through Sam's Club in late spring 1999.
After a successful test market, the national rollout anticipated for
year 2000 was accelerated to begin at the end of 1999. In December
1999 HSS announced that it had developed another marketing relationship
with TruServ Corporation, the cooperative entity for True Value
Hardware Stores. A nationwide rollout in the TruServ family of
businesses will begin in 2000. HSS is seeking equity investors to
finance this national rollout. As of December 31, 1999, SmartEnergy has
a net investment of $2.1 million.

Rates and Regulation

The Company recognizes that adequate and timely rate relief is
necessary if the Company is to maintain its financial strength,
particularly since Vermont regulatory rules do not allow for changes in
purchased power and fuel costs to be automatically passed on to
consumers through rate adjustment clauses. The Company intends to
continue its practice of periodically reviewing costs and requesting
rate increases when warranted.

Vermont

1998 Retail Rate Case: On June 12, 1998, the Company filed with
the PSB for a 10.7% retail rate increase to be effective March 1, 1999.
This rate case proceeding supplanted the 6.6% rate increase request
referenced below that is now stayed pending a review on the so-called
preclusion issue by the VSC. On October 27, 1998, the Company reached
an agreement with the DPS regarding the 10.7% rate increase request.

The agreement, which was approved by the PSB on December 11, 1998,
provides for a temporary rate increase in the Company's Vermont retail
rates of 4.7% or $10.9 million on an annualized basis beginning with
service rendered January 1, 1999 and sets the Company's authorized
return on equity in its Vermont retail business at 11% before
disallowances in connection with the Hydro-Quebec Contract.

The 4.7% rate increase is subject to retroactive or prospective
adjustment upon future resolution of issues arising under the VJO Power
Contract presently before the VSC. The agreement temporarily disallows
approximately $7.4 million for the Company's purchased power costs
under the VJO Power Contract pending resolution of the issues before
the VSC. As a result of the 4.7% rate increase agreement, during the
fourth quarter of 1998 and 1999, the Company recorded pre-tax losses of
$7.4 million and $2.9 million for disallowed purchased power costs,
representing the Company's estimated under-recovery of power costs,
prior to further resolution, under the VJO Power Contract for calendar
year 1999 and the first quarter of year 2000, respectively. If in the
future, the Company is unable to increase rates to recover the
temporary disallowed purchased power costs prior, to further
resolution, under the VJO power contract or otherwise mitigate these
costs, the Company would be required to record losses for any estimated
future under recovery. At this time, the Company does not believe that
such a loss is probable.

These temporary disallowances were calculated using comparable
methodology to that used by the PSB in the GMP rate case on February
28, 1998. In that case, the PSB found GMP's decision to commit to the
VJO Power Contract in 1991 "imprudent" and that power purchased under
it was not "used and useful." As a result, the PSB concluded that a
portion of GMP's current costs should not be imposed on GMP's customers
and were disallowed. GMP is appealing that rate order to the Vermont
Supreme Court. Should the Company receive a similar order from the PSB,
the Company would experience a material adverse effect on its results
of operations and financial condition.

Assuming an unfavorable VSC ruling and depending on the
methodology used to determine the amount of any permanent disallowance,
its future impact could be more or less than the 1999 $7.4 million
temporary disallowance or the $2.9 million first quarter 2000 temporary
disallowance. If the Company receives an unfavorable ruling from the
VSC and the PSB subsequently issues a final rate order adopting the
disallowance methodology used to determine the temporary Hydro-Quebec
disallowance described above for the duration of the VJO Power
Contract, the Company would not be able to recover approximately $198.2
million of power costs over the life of the contract, including $11.5
million in 2000, $11.6 million in 2001, $11.8 million in 2002, $11.9 in
million 2003 and $12.1 million in 2004. In such an event, the Company
would be required to take an immediate charge to earnings of
approximately $198.2 million (pre-tax). Such an outcome could
jeopardize the ability of the Company to continue as a going concern.

1997 Retail Rate Case: On September 22, 1997, the Company filed
for a 6.6% or $15.4 million general rate increase to become effective
June 6, 1998 to offset the increasing cost of providing service. $14.3
million or 92.9% of the rate increase request was to recover
contractual increases in the cost of power the Company purchases from
Hydro-Quebec. At the same time, the Company also filed a request to
eliminate the then current differential between the rates charged
customers in the summer and the rates charged customers in the winter
and price electricity the same year-round. The change would be
revenue-neutral within classes of customers and overall. Over time,
customers would see a leveling off of rates so they would pay the same
per kilowatt-hour during the winter and summer months.

In response to the Company's filing, the PSB decided to appoint an
independent investigator to examine the Company's decision to buy power
from Hydro-Quebec. The Company made a filing with the PSB stating that
the PSB as well as other parties should be barred from reviewing past
decisions because the PSB already examined the Company's decision to
buy power from Hydro-Quebec in a 1994 rate case in which the Company
was penalized for "improvident power supply management." During
February 1998, the DPS filed testimony in opposition to the Company's
retail rate increase request. The DPS recommended that the PSB instead
reduce the Company's then current retail rates by 2.5% or $5.7 million.
The Company sought, and the PSB granted, permission to stay this rate
case and to file an interlocutory appeal of the PSB's denial of the
Company's motion to preclude a re-examination of the Company's
Hydro-Quebec contract in 1991. The Company has argued its position
before the VSC. The VSC has not yet rendered a decision and it is
uncertain at this time when a decision is forthcoming.

On February 28, 1998 the PSB issued an Order in a GMP rate case.
That Order found GMP's decision to lock-in the Hydro-Quebec VJO
contract in 1991 imprudent and further found that the contract was not
used and useful. As such, the PSB concluded that a large portion of
the contract's current costs should not be imposed on GMP's consumers
and were disallowed. GMP appealed this rate order to the VSC. The
Company is one of the participants in the Hydro-Quebec VJO contract.
If the Company were to eventually receive a rate order that would
result in disallowance of Hydro-Quebec power costs on a permanent basis
similar to that contained in the GMP February 28, 1998 rate order, the
Company's ability to continue as a going concern could be jeopardized.
Because of these risks and because the PSB rejected the Company's claim
that the PSB was precluded from again trying the Company on certain
Hydro-Quebec and related C&LM issues, the Company concluded that it was
necessary to have the so-called preclusion issue reviewed by the VSC
before the PSB issues a final order in the Company's 6.6% rate increase
request. Refer to Note 13 to the Consolidated Financial Statements for
related information.

New Hampshire

Connecticut Valley's retail rate tariffs, approved by the New
Hampshire Public Utilities Commission ("NHPUC") contain a Fuel
Adjustment Clause ("FAC"), and a Purchased Power Cost Adjustment
("PPCA"). Under these clauses, Connecticut Valley recovers its
estimated annual costs for purchased energy and capacity which are
reconciled when actual data is available.

On November 26, 1997, Connecticut Valley filed a request with the
NHPUC to increase FAC, PPCA and short-term energy purchase rates
effective on or after January 1, 1998. The requested increase in rates
resulted from higher forecast energy and capacity charges on power
Connecticut Valley purchases from the Company plus removal of a credit
effective during 1997 to refund over collections from 1996.

In an Order dated December 31, 1997 in Connecticut Valley's FAC
and PPCA docket, the NHPUC found Connecticut Valley acted imprudently
by not terminating the wholesale contract between Connecticut Valley
and the Company, notwithstanding the stays of its February 28, 1997
Orders. The NHPUC Order further directed Connecticut Valley to freeze
its current FAC and PPCA rates (other than short term rates to be paid
to certain Qualifying Facilities) effective January 1, 1998, on a
temporary basis, pending a hearing to determine: 1) the appropriate
proxy for a market price that Connecticut Valley could have obtained
if it had terminated its wholesale contract with the Company; 2) the
implications of allowing Connecticut Valley to pass on to its customers
only that market price; and 3) whether the NHPUC's final determination
on the FAC and PPCA rates should be reconciled back to January 1, 1998
or some other date. See Electric Industry Restructuring discussed
below and Note 13 to the Consolidated Financial Statements for
additional information.

On April 9, 1998 the Court issued a preliminary injunction against
the NHPUC and directed and required the NHPUC to allow Connecticut
Valley to recover through retail rates all costs for wholesale power
requirements service that Connecticut Valley purchases from the Company
pursuant to its FERC-authorized wholesale rate schedule effective
January 1, 1998 until further court order. Connecticut Valley received
an order from the NHPUC authorizing retail rates to recover such costs
beginning in May 1998.

On November 24, 1998, Connecticut Valley filed with the NHPUC its
annual FAC/PPCA rates to be effective January 1, 1999. On January 4,
1999, the NHPUC issued an Order allowing Connecticut Valley to
implement the proposed FAC rate of $.008 per KWH and the proposed PPCA
rate of $.01000 per KWH, on a temporary basis, effective on all bills
rendered on or after January 1, 1999. In addition, the NHPUC also
ordered Connecticut Valley to pay refunds plus interest to its retail
customers for any overcharges collected as a result of the April 9,
1998 Federal District Court Order, should it be overturned or modified.

As a result of the December 3, 1998 Court of Appeals' decision,
see New Hampshire Retail Rates/Federal Court Proceedings below, on
March 22, 1999, the NHPUC issued an Order which directed Connecticut
Valley to file within five business days its calculation of the
difference between the total FAC and the PPCA revenues that it would
have collected had the 1997 FAC and PPCA rate levels been in effect the
entire year. In its Order, the NHPUC also directed Connecticut Valley
to calculate a rate reduction to be applied to all billings for the
period April 1, 1999 through December 31, 1999 to refund the 1998 over
collection relative to the 1997 rate level. The Company estimated this
amount to be approximately $2.7 million on a pre-tax basis.
Connecticut Valley filed the required tariff page with the NHPUC, under
protest and with reservation of all rights, on March 26, 1999 and
implemented this refund effective April 1, 1999.

The NHPUC held a hearing on April 22, 1999 to determine whether to
modify Connecticut Valley's 1999 power rates by returning the rates to
the levels that were in effect on December 31, 1997. On May 17, 1999,
the NHPUC issued an order requiring Connecticut Valley to set temporary
rates at the level in effect as of December 31, 1997, subject to future
reconciliation effective with bills issued on and after June 1, 1999.

On December 1, 1999, Connecticut Valley filed with the NHPUC a
petition for a change in its FAC and PPCA rates effective on bills
rendered on and after January 1, 2000. On December 30, 1999, the NHPUC
denied Connecticut Valley's request to increase its FAC and PPCA rates
above those in effect at December 31, 1997 subject to further
investigation and reconciliation until otherwise ordered by the NHPUC.

Proposed Formation of Holding Company

In order to further prepare Central Vermont Public Service
Corporation for deregulation, on July 24, 1998, the Company filed a
petition with the PSB for permission to create a holding company that
would have as subsidiaries the Company and non-utility subsidiaries,
Catamount and SmartEnergy. The Company believes that a holding company
structure will facilitate the Company's transition to a deregulated
electricity market. The proposed holding company formation must also
be approved by Federal regulators, including the Securities and
Exchange Commission and the FERC, and by the Company's shareholders.

Year 2000 Information Systems Modifications

The Company experienced no failures or business interruptions as a
result of the transition from December 31, 1999 to January 1, 2000 and
for the transition of the leap year date from February 28, 2000 to
February 29, 2000. To date, the Company has also been successful with
all transactions with its principal power and transmission suppliers as
well as other vendors and suppliers, and does not anticipate any
problems will surface in the future.

The Company is part of the Northeast grid contingency plan to
provide electricity to its customers on a priority basis in the event
of power outages. The Company also has other contingency plans
developed in the event of the failure of its transmission, generation,
distribution, metering, telecommunications, information and public
communications systems.

As previously estimated, the Company has incurred $4.0 million to
date to make the necessary modifications to its computer systems and
for its contingency plans. In accordance with a PSB Accounting Order,
the Company has deferred a portion of these costs which will be
amortized over a five-year period beginning January 1, 2000. Per PSB
Order dated December 11, 1998, the Company is authorized to seek
recovery of these costs through future regulatory proceedings.

ELECTRIC INDUSTRY RESTRUCTURING

The electric utility industry is in a period of transition that
may result in a shift away from rate making based on cost of service
and return on equity to more market-based rates with energy sold to
customers by competing retail energy service providers. Many states,
including Vermont and New Hampshire, where the Company does business,
are exploring new mechanisms to bring greater competition, customer
choice and market influence to the industry while retaining the public
benefits associated with the current regulatory system.

Vermont

Recently, there have been three primary sources of Vermont
governmental activity in attempting to restructure the electric
industry in Vermont: (1) the Governor's Working Group, created by the
Governor of Vermont; (2) the PSB's Docket No. 6140, through which the
PSB considered restructuring proposals; (3) the PSB's Docket No. 6330,
through which the PSB is considering the establishment of policies and
procedures to govern retail competition with the Company's service
territory.

The Working Group

On July 22, 1998, the Governor of Vermont issued an Executive
Order establishing the Working Group on Vermont's Electricity Future to
lead a new effort to review the issues of potential restructuring of
Vermont's electric industry. The Working Group was created to determine
how restructuring the electric industry in Vermont could reduce both
current and long-term electric costs for all classes of Vermont
electric consumers. The Working Group was asked to provide a fact-based
analysis of the options for electric industry restructuring and the
impact of such industry changes on consumers and upon Vermont
utilities. Further, the Working Group was directed by the Governor of
Vermont to gather information on and evaluate the possible consequences
of the current financial status of Vermont electric utilities.

A report was issued by the Working Group on December 18, 1998. Key
conclusions of its report were:

- The bankruptcy of Vermont electric utilities should not be viewed
as an appropriate means to reduce Vermont utilities' above-market
power supply costs.

- Vermont should restructure its electric industry by moving
rapidly to retail choice whereby consumers would purchase power
directly from competing power suppliers.

- Vermont electric utilities should pursue power contract
renegotiations through payments to buy down power contracts or
buy-out power contracts. Financing for such payments should be
obtained in the capital markets after a comprehensive regulatory
process dealing with all of the elements of the restructuring of
the Vermont electric utility industry.

- The Vermont electric utilities should pursue auctions of their
power generation assets and remaining power contracts.

- Consolidation of existing electric utilities in Vermont (there
are currently 22 utilities) should be considered in order to
effect additional savings for utility customers.

The Working Group noted that by March 1, 2000, most New Englanders
outside Vermont will have a choice of their power supplier. While New
England has the highest electricity rates in the nation, electricity
costs in Vermont have been among the lowest in the region, although our
rates are higher than the Vermont average. However, that advantage is
eroding as other states in New England restructure their electric
utility industries. Therefore, the Working Group noted that it is in the
interest of Vermont ratepayers to have the benefit of a restructured
electric utility industry as soon as possible.

Public Service Board Docket No. 6140

On September 15, 1998, the PSB opened a formal proceeding in Docket
No. 6140 with the goal of creating a regulatory environment and a
procedural framework to call forth, for disciplined review, proposals
for reducing current and future power costs in Vermont. The PSB intended
that this proceeding would define one or more acceptable courses for
reform. All Vermont utilities were made a party to that proceeding.
Subsequent to the PSB's announcement, preliminary position papers were
filed and a series of technical conferences were convened with the PSB
to recommend the scope of the investigation, potential courses for
reform of Vermont's power supply and other matters associated therewith
including the consideration of the
Working Group's recommendations.

On March 3, 1999, the Company filed its Restructuring Plan, a
Working Plan to restructure a significant portion of Vermont's Electric
Utility Industry, with the PSB and parties in Docket No. 6140. The
Company's plan was a joint plan with GMP. On July 12, 1999, the PSB
issued a Status Order concluding that the objective of implementing
power supply reform may be advanced more effectively in ways other than
holding further technical conferences in this docket. Absent good
reason to hold one or more technical conferences pertinent to power
supply reform, the PSB indicated that the docket would be closed on
December 31, 1999, which action has occurred. As a companion proceeding
to its investigation in Docket No. 6140, on January 19, 1999, the PSB
issued an order opening a new contested case proceeding, Docket No.
6140-A, where it indicated that it intended to issue final, binding and
appealable orders concerning matters related to the reform and
restructuring of Vermont's electric utility industry. Initially, the PSB
notified parties that it intended proceedings in Docket No. 6140-A to
consider matters associated with the bankruptcy of one or more of the
Vermont electric utilities. After an opportunity for comment, the focus
of the proceeding was amended to first consider the principles,
authority and proposals for reform of Vermont's electric power supply.
This includes issues associated with the scope and extent of the Board's
authority to approve "securitization" and other financings proposed to
be entered into in connection with the buy-out or buy-down of power
contracts and the criteria to be applied by the PSB when considering
voluntary utility restructuring proposals.

By Order dated June 24, 1999 in Docket 6140-A, the PSB formally
adopted the Vermont Principles on Electric Utility Restructuring. The
Order explains that proposals to open utility franchise service areas to
retail competition, including our Restructuring Plan, will only be
approved if they can be found to satisfy the public good after due
consideration is given to each of 14 Restructuring Principles. If one or
more of the principles is not satisfied by the proposal, then the
proponent must offer justification for the deficiency and demonstrate
satisfaction of certain statutory requirements. As such, the PSB stated
that any filing proposing to open a franchise territory to retail choice
would have to be supported, at a minimum, by an explanation of how that
proposal fulfills the policy objectives established by the Vermont
Principles on Electric Utility Restructuring.

With regard to financing, no party to the investigation asked that
the PSB clarify its authority or issue a declaratory ruling concerning
the criteria to be considered when approving utility financings for the
buy-out or buy-down of committed power contracts. During the
investigation, both the Company and Green Mountain Power Corporation
asserted that anticipated refinancing approaches could be accomplished
utilizing the existing Vermont and federal legislative regime that
governs the regulation of electric utilities and that "securitization"
style financings were not presently being contemplated. Because no party
to the Docket contradicted these statements, the Board accepted our
assertions and took no further action to evaluate specific utility
financing proposals.

In contrast, Vermont Electric Power Producers, Inc.("VEPP"),
purchasing agent for the purchase of power from qualifying facilities
pursuant to PSB Rule 4.100, proposed to use administrative
securitization to finance the reform of its power purchase contracts.
However, at the request of all commenting parties, the PSB determined to
withhold judgment on the issue as to whether the PSB had jurisdiction to
authorize a VEPP financing until such time as a specific proposal was
actually filed with the PSB. Toward this end, the PSB has stated that it
will convene a workshop, independent of this Docket, to further discuss
VEPP's financing proposal and to prepare for the opening of a possible
rulemaking proceeding to amend Rule 4.100 on this topic. In the absence
of any requests for further investigation or action to be filed within
30 days of the Docket No. 6140-A Order, the PSB indicated that this
investigation would be closed, which action has occurred.

The Company supports the Working Group recommendations described
above and believes that the restructuring of the electric industry is
essential to improve our financial position, enhance our ability to
effectively compete in a changing electric utility industry and
stabilize projected costs.

As a result, the Company is pursuing a comprehensive financial
Restructuring Plan, certain elements of which were included in a report
that the Company and GMP filed with the PSB in the first quarter of 1999
in connection with the proceedings in Docket No. 6140 described above.
The Company is aggressively pursuing implementation of the Restructuring
Plan which includes the following elements:

- Retail choice: voluntarily giving up the exclusive right to
supply power to the Company's present electric customers, while
retaining its rights as a distribution company, as part of a
global settlement of regulatory issues.

- Renegotiation of certain purchase power contracts: reducing the
Company's future cost of power by renegotiating power contracts,
specifically those with Hydro-Quebec and the Vermont purchasing
agent's contracts with IPPs which together represent
approximately 40% of the Company's 1998 net energy supply. The
Company may seek to finance the cost of any buy-outs or
buy-downs of power contracts through the future issuance of
securities in the capital markets.

- Contract and asset disposition: seeking to sell power purchase
contracts and generating assets, including the interest in the
Vermont Yankee nuclear generating plant. On October 15, 1999,
the Company and the other owners of Vermont Yankee accepted a
bid for sale of the plant to AmerGen Energy Company, which is
owned by PECO Energy Company and British Energy. This
transaction will also involve taking back a contract to purchase
a portion of the power produced by this plant. The Vermont
Yankee sale needs to be approved by numerous state and
federal regulatory bodies. On November 4, 1999 the PSB opened
Docket No. 6300 to consider the issues attendant to the approval
of the sale of Vermont Yankee and approval of various related
agreements including the Company's agreement to continue to
purchase its share of the output of Vermont Yankee.

- Cost-cutting: implementing cost-cutting measures to reduce cash
flow requirements while maintaining safety and reliability
standards.

- Holding company: establishing a holding company in order to
further prepare the Company for deregulation.

- Industry consolidation: evaluating possible consolidation with
other Vermont electric distribution companies.

- Regulatory settlement: seeking a comprehensive regulatory
settlement that leads to long-term financial stability.

- Energy efficiency activities: creating a state sponsored
"energy-efficiency utility" to take over most system-wide
energy-efficiency services for electric customers. On
September 30, 1999, the PSB issued a final Order approving a
Memorandum of Understanding between the Company, the Vermont
Department of Public Service, all other Vermont electric utility
companies and other interested parties that calls for the
establishment of the energy-efficiency utility and provides for
its funding via a separate stated Energy Efficiency Charge.

The Company believes that implementation of its Restructuring Plan
is a critical element to improving its future financial performance and
to providing its customers with more stable electric rates and the
continuation of efficient and reliable electric service. The key
contingency of the Company's Restructuring Plan is regulatory approval
of a rate schedule that will allow the Company to recover the costs of
the restructuring. If the financial restructuring described in this
section is completed in conjunction with the deregulation of Vermont's
electric industry described in "Electric Industry Restructuring," the
Company anticipates that its utility financial performance and prospects
will improve significantly.

Public Service Board Docket No. 6330

On November 23, 1999, the Company and GMP or the Companies filed a
joint Petition and Supporting Materials with the PSB asking that the PSB
open an investigation to establish retail access policies and procedures
to resolve issues that must be decided to implement the Companies'
Restructuring Plan. Specifically, the Petition requests that the PSB
issue such orders and approvals as are necessary or advisable to:

1) permit the Companies to suspend their provision of power supply
Services, or Generation Service to customers located within
their service territories;

2) permit the Companies to amend their service tariff obligations
to clarify that they retain their exclusive service franchises
as providers of electric delivery services, or Delivery Service
to customers within their respective service territories;

3) permit the Companies to implement a Retail Open Access Tariff,
or "R-OAT" that enables customers located within the Companies'
respective service territories to choose their power supplier
from an array of approved energy service providers ("ESP"),
and to purchase Generation Service from such ESPs at
market-determined prices;

4) select through a competitive bidding process an ESP or ESPs to
deliver "Default Service" for energy to customers located
within the Companies' service territories;

5) select through a competitive bidding process an ESP or ESPs to
deliver "Transition Service" for energy to customers located
within the Companies' service territories; and

6) approve revisions and modifications to the Companies' tariffs
to implement voluntary retail access within the Companies'
respective service territories as provided for pursuant to this
Petition.

The consent to retail access within the Companies' service areas
established by the Petition is voluntary and conditional. Pursuant to
the Petition, the Company's' consent to customer choice and retail
competition is expressly conditioned upon approval of all elements of
the Companies' Restructuring Plan including the approval of any proposed
mitigation measures to reduce power costs and financing measures related
thereto, and a mechanism to recover the costs rendered stranded on
account of the move to retail access and customer choice.

On January 14, 2000, the PSB opened Docket No. 6330 to consider the
issues raised by the Companies' petition. In its opening Order, the
Board states:

"The scope of this investigation is intended to address many of
the more detailed aspects of retail open access. While current
law may not permit this Board to require retail open access of
Vermont utilities, the companies are clearly able to open their
service territories on a voluntary basis. Whether retail open
access is established on a voluntary basis through existing
statutes or through revised legislation, there are many
technical issues to be resolved. This investigation will serve
to advance many aspects of issues surrounding retail open
access."

An initial pre-hearing conference was held in this investigation on
January 31, 2000. At this time, it is premature to predict the date
upon which a final PSB resolution of the matters raised in this
investigation will be decided although, the Companies proposed an
initial start date for retail competition of September 1, 2001, provided
that all of the elements of the joint Restructuring Plan are completed
by that time.

New Hampshire Retail Rates/Federal Court Proceedings

On February 28, 1997 the NHPUC published its detailed Final Plan to
restructure the electric utility industry in New Hampshire. Also on
February 28, 1997, the NHPUC, in a supplemental order specific to
Connecticut Valley, found that Connecticut Valley was imprudent for not
terminating the FERC-authorized power contract between Connecticut
Valley and the Company, required Connecticut Valley to give notice to
cancel its contract with the Company and denied stranded cost recovery
related to this power contract. Connecticut Valley filed for rehearing
of the February 28, 1997 NHPUC Order.

On April 7, 1997, the NHPUC issued an Order addressing certain
threshold procedural matters raised in motions for rehearing and/or
clarification filed by various parties, including Connecticut Valley,
relative to the Final Plan and interim stranded cost orders. The April
7, 1997 Order stayed those aspects of the Final Plan that were the
subject of rehearing or clarification requests and also stayed the
interim stranded cost orders for the various parties, including
Connecticut Valley. As such, those matters pertaining to the power
contract between Connecticut Valley and the Company were stayed. The
suspension of these orders was to remain in effect until two weeks
following the issuance of any order concerning outstanding requests for
rehearing and clarification.

On November 17, 1997, the City of Claremont, New Hampshire
("Claremont"), filed with the NHPUC a petition for a reduction in
Connecticut Valley's electric rates. Claremont based its request on the
NHPUC's earlier finding that Connecticut Valley's failure to terminate
its wholesale power contract with the Company as ordered in the NHPUC
Stranded Cost Order of February 28, 1997 was imprudent. Claremont
alleged that if Connecticut Valley had given written notice of
termination to the Company in 1996 when legislation to restructure the
electric industry was enacted in New Hampshire, Connecticut Valley's
obligation to purchase power from the Company would have terminated as
of January 1, 1998.

On November 26, 1997, Connecticut Valley filed a request with the
NHPUC to increase the FAC, PPCA and short-term energy purchase rates
effective on or after January 1, 1998. The requested increase in rates
resulted from higher forecast energy and capacity charges on power
Connecticut Valley purchases from the Company plus removal of a credit
effective during 1997 to refund over collections from 1996. Connecticut
Valley objected to the NHPUC's notice of intent to consolidate
Claremont's petition into the FAC and PPCA docket, stating that
Claremont's complaint should be heard as part of the NHPUC restructuring
docket. Over Connecticut Valley's objection at the hearing on December
17, 1997, the NHPUC consolidated Claremont's petition with Connecticut
Valley's FAC and PPCA proceeding.

In an Order dated December 31, 1997 in Connecticut Valley's FAC and
PPCA docket, the NHPUC found Connecticut Valley acted imprudently by not
terminating the wholesale contract between Connecticut Valley and the
Company, notwithstanding the stays of its February 28, 1997 Orders. The
NHPUC Order further directed Connecticut Valley to freeze its current
FAC and PPCA rates (other than short term rates to be paid to certain
Qualifying Facilities) effective January 1, 1998, on a temporary basis,
pending a hearing to determine: 1) the appropriate proxy for a market
price that Connecticut Valley could have obtained if it had terminated
its wholesale contract with the Company; 2) the implications of allowing
Connecticut Valley to pass on to its customers only that market price;
and 3) whether the NHPUC's final determination on the FAC and PPCA rates
should be reconciled back to
January 1, 1998 or some other date.

On January 19, 1998, Connecticut Valley and the Company filed with
the Court for a temporary restraining order to maintain the status quo
ante by staying the December 31, 1997 NHPUC Order and preventing the
NHPUC from taking any action that (i) compromises cost-based rate making
for Connecticut Valley or otherwise seeks to impose market price-based
rate making on Connecticut Valley; (ii) interferes with the FERC's
exclusive jurisdiction over the Company's pending application to recover
wholesale stranded costs upon termination of its wholesale power
contract with Connecticut Valley; or (iii) prevents Connecticut Valley
from recovering through retail rates the stranded costs and purchased
power costs that it incurs pursuant to its FERC-authorized wholesale
rate schedule with the Company.

On February 23, 1998, the NHPUC announced in a public meeting that
it reaffirmed its finding of imprudence and designated a proxy market
price for power at 4 cents per kWh in lieu of the actual costs incurred
pursuant to the wholesale power contract with the Company. In addition,
the NHPUC indicated, subject to certain conditions which were
unacceptable to the companies, that it would permit Connecticut Valley
to maintain its current rates pending a decision in Connecticut Valley's
appeal of the NHPUC Order to the New Hampshire Supreme Court.

Based on the December 31, 1997 NHPUC Order as well as the NHPUC's
February 23, 1998 announcement, which resulted in the establishment of
Connecticut Valley's rates on a non cost-of-service basis, Connecticut
Valley no longer qualified, as of December 31, 1997, for the application
of SFAS No. 71. As a result, Connecticut Valley wrote-off all of its
regulatory assets associated with its New Hampshire retail business as
of December 31, 1997. This write-off amounted to $1.2 million on a
pre-tax basis. In addition, Connecticut Valley recorded a $5.5 million
pre-tax loss in 1997 for disallowed power costs.

On March 20, 1998, the NHPUC issued an order which affirmed,
clarified and modified various generic policy statements including the
reaffirmation to establish rates on the basis of a regional average
announced previously in its February 28, 1997 Final Plan. The March 20,
1998 order also addressed all outstanding motions for rehearings or
clarification relative to the policies or legal positions articulated in
the Final Plan and removed the stay covering the Company's interim
stranded cost order of April 7, 1997. In addition, the March 20, 1998
Order imposed various compliance filing requirements.

On April 3, 1998, the Court held a hearing on the Companies' motion
for a Temporary Restraining Order, or TRO, and Preliminary Injunction
against the NHPUC at which time both the Companies and the NHPUC
presented arguments. In an oral ruling from the bench, and in a written
order issued on April 9, 1998, the Court concluded that the Companies
had established each of the prerequisites for preliminary injunctive
relief and directed and required the NHPUC to allow Connecticut Valley
to recover through retail rates all costs for wholesale power
requirements service that Connecticut Valley purchases from the Company
pursuant to its FERC-authorized wholesale rate schedule effective
January 1, 1998 until further court order. Connecticut Valley received
an order from the NHPUC authorizing retail rates to recover such costs
beginning in May 1998. On April 14, 1998, the NHPUC filed a notice of
appeal and a motion for a stay of the Court's preliminary injunction.
The NHPUC's request for a stay was denied. At the same time, the NHPUC
permitted Connecticut Valley to recover in rates the full cost of its
wholesale power purchases from the Company.

Also, on April 3, 1998, the Court indicated that its earlier TRO
enjoining the NHPUC's restructuring orders applied to Connecticut Valley
and prohibits the enforcement of the restructuring orders until the
Court conducts a consolidated hearing and rules on the requests for
permanent injunctive relief by plaintiff PSNH and the other utilities
that had been allowed to intervene in these proceedings, including the
Company and Connecticut Valley. The plaintiffs-intervenors thereafter
filed a motion asking the Court to extend its stay of action by the
NHPUC to implement restructuring and to make clear that the stay
encompasses the NHPUC's order of March 20, 1998.

As a result of these Court orders, Connecticut Valley's 1997
charges described above were reversed in the first quarter of 1998.
Combined, the reversal of these charges increased first quarter 1998 net
income and earnings per share of common stock by $4.5 million and $.39,
respectively.

On April 1, 1998, Citizens Bank of New Hampshire, or Bank, notified
Connecticut Valley that it was in default of the Loan Agreement between
the Bank and Connecticut Valley dated December 27, 1994 and that the
Bank would exercise all of its remedies from and after May 5, 1998 in
the event that the violations were not cured. After reversing the 1997
write-offs described above, Connecticut Valley was in compliance with
the financial covenants associated with its $3.75 million loan with the
Bank. As a result, Connecticut Valley satisfied the Bank's requirements
for curing the violation.

On May 11, 1998 the NHPUC issued an order requiring Connecticut
Valley to show cause why it should not be held in contempt for its
failure to meet the compliance filing requirements of its March 20, 1998
Order. A hearing on this matter was scheduled for June 11, 1998, which
was subsequently canceled because of the Court's June 5, 1998 Order,
discussed below.

On June 5, 1998, the Court issued an Order which denied the NHPUC's
motion for a stay of the Court's preliminary injunction. The Order
clearly states that no restructuring effort in New Hampshire can move
forward without the Court's approval unless all New Hampshire utilities
agree to the plan. The Order suspended all involuntary restructuring
efforts for all New Hampshire utilities until a hearing is conducted.
The NHPUC appealed this Order to the United States First Circuit Court
of Appeals ("Court of Appeals").

On July 23, 1998, the NHPUC issued an order vacating that portion
of its February 27, 1997 restructuring order that had directed
Connecticut Valley to terminate its RS-2 wholesale power purchases from
the Company. The NHPUC has expressly stated in federal court filings
that its July 23, 1998 order "clarified that Connecticut Valley should
not terminate the RS-2 Rate Schedule if such termination would trigger
the exit fee" for which the Company has sought authorization from FERC.

On November 24, 1998, Connecticut Valley filed with the NHPUC its
annual FAC/PPCA rates to be effective January 1, 1999. On January 4,
1999, the NHPUC issued an Order allowing Connecticut Valley to implement
the proposed FAC rate of $.008 per KWH and the proposed PPCA rate of
$.01000 per KWH rate on a temporary basis, effective on all bills
rendered on or after January 1, 1999. In addition, the NHPUC also
ordered Connecticut Valley to pay refunds plus interest to its retail
customers for any overcharges collected as a result of the April 9, 1998
Court Order should it be overturned or modified, which are included in
the estimated total losses of $4.3 million discussed below.

On December 3, 1998, the Court of Appeals announced its decisions
on the appeals taken by the NHPUC from the preliminary injunctions
issued by the Court. Those preliminary injunctions had stayed
implementation of the NHPUC's plan to restructure the New Hampshire
electric industry and required the NHPUC to allow Connecticut Valley to
recover through its retail rates the full cost of wholesale power
obtained from the Company.

The Court of Appeals affirmed the preliminary injunction, issued by
the Court, staying restructuring until the plaintiff utilities' claims
(including those of the Company and Connecticut Valley) are fully tried.
The Court of Appeals found that PSNH had sufficiently established that
without the preliminary injunction against restructuring it would suffer
substantial irreparable injury and that it had sufficient claims against
restructuring to warrant a full trial. The Court of Appeals also
affirmed the extension of the preliminary injunction to protect the
other plaintiff utilities, including Connecticut Valley and the Company,
although it questioned whether the other utilities had arguments as
strong against restructuring as PSNH because they did not have formal
agreements with the State similar to PSNH's Rate Agreement. The Court
of Appeals stated that if the Court awards the utilities permanent
injunctive relief against restructuring after the case is tried, then it
must explain why the other utilities are also entitled to such relief.
The NHPUC filed a petition for rehearing on December 17, 1998. The
Court of Appeals denied the petition on January 13, 1999.

The Court of Appeals also reversed the Court's preliminary
injunction requiring the NHPUC to allow Connecticut Valley to recover in
retail rates the full cost of the power it buys from the Company.
Although the Court of Appeals found that Connecticut Valley and the
Company had made a strong showing of irreparable injury to justify the
preliminary injunction, it concluded that Connecticut Valley's and the
Company's claims did not have a sufficient probability of success to
warrant such preliminary relief. The Court of Appeals explained that
the filed-rate doctrine preserving the exclusive jurisdiction of the
FERC over wholesale power rates did not prevent the NHPUC from deciding
whether Connecticut Valley's power purchases from the Company were
prudent given alternative available sources of wholesale power. The
Court of Appeals then stated that Connecticut Valley's rates could be
reduced to the level prevailing on December 31, 1997. However, the
Court of Appeals also stated that if the NHPUC ordered Connecticut
Valley's rates to be reduced below the level existing as of December 31,
1997, "it will be time enough to consider whether they are precluded
from the Court's injunction against the Final Plan or on other grounds."

On December 17, 1998, Connecticut Valley and the Company filed a
petition for rehearing on the grounds that the Court of Appeals had not
given sufficient weight to the Court's factual findings and that the
Court of Appeals had misapprehended both factual and legal issues.
Connecticut Valley and the Company also asked that the entire Court of
Appeals, rather than only the three-judge appellate panel that had
issued the December 3 decision, consider their petition for rehearing.
On January 13, 1999, the Court denied the petition for rehearing.

Connecticut Valley and the Company then requested the Court of
Appeals to stay the issuance of its mandate until the companies could
file a petition for certiorari to the United States Supreme Court and
the Supreme Court acted on the petition.

On January 22, 1999, the Court of Appeals denied the request.
However, the Court of Appeals granted a 21-day stay to enable the
Company to seek a stay pending certiorari from the Circuit Justice of
the Supreme Court. On February 11, 1999, the Company and Connecticut
Valley filed a petition for a writ of certiorari with the United States
Supreme Court and a motion to stay the effect of the Court of Appeals'
decision while the case was pending in the Supreme Court. The motion
for a stay was addressed to Justice Souter who is responsible for such
motions pertaining to the Court of Appeals for the First Circuit. On
February 18, 1999, Justice Souter denied the stay pending the petition
for certiorari. On April 19, 1999, the Supreme Court denied the
petition for certiorari.

As a result of the December 3, 1998 Court of Appeals' decision
discussed above, on March 22, 1999, the NHPUC issued an Order which
directed Connecticut Valley to file within five business days its
calculation of the difference between the total FAC and PPCA revenues
that it would have collected had the 1997 FAC and PPCA rate levels been
in effect the entire year. In its Order, the NHPUC also directed
Connecticut Valley to calculate a rate reduction to be applied to all
billings for the period April 1, 1999 through December 31, 1999 to
refund the 1998 over collection relative to the 1997 rate level. The
Company estimated this amount to be approximately $2.7 million on a
pre-tax basis. Connecticut Valley filed the required tariff page with
the NHPUC, under protest and with reservation of all rights, on March
26, 1999 and implemented the refund effective April 1, 1999.

As a result of legal and regulatory actions discussed above,
Connecticut Valley no longer qualified as of December 31, 1998 for the
application of SFAS No. 71, and wrote-off in the fourth quarter of 1998
all its regulatory assets associated with its New Hampshire retail
business estimated at approximately $1.3 million on a pre-tax basis at
December 31, 1998. In addition, Connecticut Valley recorded estimated
total losses of $4.3 million pre-tax during the fourth quarter of 1998
for disallowed power costs of $1.6 million and its refund obligations of
$2.7 million. Company management, however, continues to believe that
the NHPUC's actions are illegal and unconstitutional and will present
its arguments in the appropriate forum.

The pre-tax losses described above resulted in Connecticut Valley
violating applicable covenants, which if not waived or renegotiated,
would have allowed Connecticut Valley's lender the right to accelerate
the repayment of a $3.75 million loan with Connecticut Valley. On March
12, 1999, Connecticut Valley was notified by the Bank that it would
exercise appropriate remedies in connection with the violation of
financial covenants associated with the $3.75 million loan agreement
unless the violation was cured by April 11, 1999. To avoid default of
this loan agreement, on April 6, 1999, pursuant to an agreement reached
on March 26, 1999, the Company purchased from the Bank the $3.75 million
note.

On April 7, 1999, the Court ruled from the bench that the March 22,
1999 NHPUC Order requiring Connecticut Valley to provide a refund to its
retail customers was illegal and beyond the NHPUC's authority. The
Court also ruled that the NHPUC cannot reduce Connecticut Valley's rates
below rates in effect at December 31, 1997. Accordingly, Connecticut
Valley removed the rate refund from retail rates effective April 16,
1999. Lastly, the Court denied the NHPUC's motion to dissolve the
injunction staying the implementation of its restructuring plan and
stated its desire to rule on the pending motion for summary judgement
and to conduct a hearing on the Company's request for a permanent
injunction, after the NHPUC completes hearings on PSNH's stranded costs.
The District Court's decision was issued as a written order on May 11,
1999.

The NHPUC held a hearing on April 22, 1999 to determine whether to
modify Connecticut Valley's 1999 power rates by returning the rates to
the levels that were in effect on December 31, 1997. On May 17, 1999,
the NHPUC issued an order requiring Connecticut Valley to set temporary
rates at the level in effect as of December 31, 1997, subject to future
reconciliation, effective with bills issued on and after June 1, 1999.

On May 24, 1999, the NHPUC filed a petition for mandamus in the
Court of Appeals challenging the Court's May 11, 1999 ruling and seeking
a decision allowing the refunds as required by the NHPUC's March 22,
1999 order. The Court of Appeals denied that petition on June 2, 1999.
The NHPUC immediately filed a notice of appeal in the Court of Appeals
again challenging the Court's May 11, 1999 ruling. In that appeal, the
Company and Connecticut Valley contend, among other things, that it is
unfair for the NHPUC to direct Connecticut Valley to continue to
purchase wholesale power under RS-2 in order to avoid the triggering of
a FERC exit fee, but at the same time to freeze Connecticut Valley's
rates at their December 31, 1997 level which does not enable Connecticut
Valley to recover all of its RS-2 costs. The Court of Appeals issued a
decision on January 24, 2000, which upheld the Court's preliminary
injunction enjoining the Commission's restructuring plan. The decision
also remanded the refund issue do the Court stating:

"The district court may defer vacation of this injunction
against the refund order for up to 90 days. If within that
period it has decided the merits of the request for a permanent
injunction in a way inconsistent with refunds, or has taken any
other action that provides a showing that the Company is likely
to prevail on the merits in federal court in barring the
refunds, it may enter a superseding injunction against the
refund order, which the Commission may then appeal to us.
Otherwise, no later than the end of the 90-day period, the
district court must vacate its present injunction insofar as it
enjoins the Commission's refund order." The parties have also
submitted motions for summary judgment to the Court, which the
Court has under consideration.

On March 6, 2000 the Court issued a permanent injunction mandating
that the NHPUC allow Connecticut Valley to pass through to its retail
customers its wholesale costs incurred under the RS-2 rate schedule with
the Company. The Court also ruled that Connecticut Valley is entitled
to recover those wholesale costs that the NHPUC has disallowed in retail
rates since January 1, 1997.

This decision is subject to implementation by the NHPUC and is
subject to appeal.

On June 14, 1999, PSNH and various parties in New Hampshire
announced that a "Memorandum of Understanding" had been reached that is
intended to result in a detailed settlement proposal to the NHPUC that
would resolve PSNH's claims against the NHPUC's restructuring plan. On
July 6, 1999, PSNH petitioned the Court to stay its proceedings
indefinitely while the proposed settlement is reviewed and approved by
the NHPUC and the New Hampshire Legislature. On July 12, 1999 the
Company and Connecticut Valley objected to any stay that would allow the
NHPUC's rate freeze order to remain in effect for an extended period and
asked the Court to proceed with prompt hearings on its summary judgement
motion and trial on the merits. On October 20, 1999 the Court heard
oral arguments pertaining to the pretrial motions of the Company and the
NHPUC for summary judgement and dismissal, respectively. The Court took
the matters under advisement and indicated that a written order would
ensue.

FERC Proceedings

The Company filed an application with the FERC in June 1997, to
recover stranded costs in connection with its wholesale rate schedule
with Connecticut Valley and a notice of cancellation of the Connecticut
Valley rate schedule (contingent upon the recovery of the stranded costs
that would result from the cancellation of this rate schedule). In
December 1997, the FERC rejected the Company's proposal to recover
stranded costs through the imposition of a surcharge on our transmission
tariff, but indicated that it would consider an exit fee mechanism for
collecting stranded costs. The FERC denied the Company's motion for a
rehearing regarding the surcharge proposal, so the Company filed a
request with the FERC for an exit fee mechanism to collect the stranded
costs resulting from the cancellation of the contract with Connecticut
Valley. The stranded cost obligation sought to be recovered through an
exit fee, expressed on a net present value basis as of January 1, 2000,
is approximately $44.9 million. During April and May 1999, nine days of
hearings were held at the FERC before an Administrative Law Judge, who
will determine, among other things, whether Connecticut Valley qualifies
for an exit fee, and if so, the amount of Connecticut Valley's stranded
cost obligation to be paid to the Company as an exit fee. The ruling of
the Administrative Law Judge is expected in the first half of 2000, and
the FERC will act on the judge's recommendations sometime thereafter.

If the Company is unable to obtain an order authorizing the
recovery of costs in connection with the June 1997 FERC filing or in the
Federal Court, it is possible that the Company would be required to
recognize a pre-tax loss under this contract totaling approximately
$56.3 million on a pre-tax basis. The Company would also be required to
write-off approximately $3.0 million (pre-tax)in regulatory assets
associated with its wholesale business. However, even if the Company
obtains a FERC order authorizing the updated requested exit fee, if
Connecticut Valley is unable to recover its costs by increasing its
rates, Connecticut Valley would be required to recognize a loss under
this contract of approximately $44.9 million (pre-tax) representing
future under recovery of power costs.

In addition to its efforts before the Court and FERC, Connecticut
Valley has initiated efforts and will continue to work for a negotiated
settlement with parties to the New Hampshire restructuring proceeding
and the NHPUC. On September 14 and 15, 1998 the Company participated in
a settlement conference with an Administrative Law Judge assigned for
the settlement process at the FERC and the parties to the Company's exit
fee filing.

An adverse resolution of these proceedings would have a material
adverse effect on the Company's results of operations and cash flows.
However, the Company cannot predict the ultimate outcome of this matter.

For further information on New Hampshire restructuring issues and
other regulatory events in New Hampshire affecting the Company or
Connecticut Valley and the 1997 and 1998 charges and reversals of the
1997 charges, see the Company's Current Reports on Form 8-K dated
January 12, 1998, January 28, 1998, April 1, 1998 and February 1, 1999;
the Company's Form 10-Q for the quarterly periods ended March 31, June
30 and September 30, 1998; and March 31, June 30 and September 30, 1999.
Also, Item 1. Business-New Hampshire Retail Rates, Item 7. Management's
Discussion and Analysis of Financial Condition and Results of
Operations-Electric Industry Restructuring-New Hampshire and Item 8.
Financial Statements and Supplementary Data-Note 13, Retail Rates-New
Hampshire in the Company's 1998 and 1997 Annual Reports on Form 10-K.

Connecticut Valley constitutes approximately 7% of the Company's
total retail mWh sales.

Competition-Risk Factors

If retail competition is implemented in Vermont or New Hampshire,
the Company is unable to predict the impact of this competition on its
revenues, the Company's ability to retain existing customers with
respect to their power supply purchases and attract new customers or the
margins that will be realized on retail sales of electricity, if any
such sales are sought. The Company expects its power distribution and
transmission service to its customers to continue on an exclusive basis
subject to continuing economic regulation.

Historically, electric utility rates have been based on a utility's
costs. As a result, electric utilities are subject to certain
accounting standards that are not applicable to other business
enterprises in general. SFAS No. 71 requires regulated entities, in
appropriate circumstances, to establish regulatory assets and
liabilities, and thereby defer the income statement impact of certain
costs and revenues that are expected to be realized in future rates.

As described in Note 1 of Notes to Consolidated Financial
Statements, the Company believes it currently complies with the
provisions of SFAS No. 71 for both its regulated Vermont service
territory and FERC regulated wholesale businesses. In the event the
Company determines that it no longer meets the criteria for following
SFAS No. 71, the accounting impact would be an extraordinary, non-cash
charge to operations of approximately $62.8 million on a pre-tax basis
as of December 31, 1999. Criteria that give rise to the discontinuance
of SFAS No. 71 include (1) increasing competition that restricts the
Company's ability to establish prices to recover specific costs and (2)
a significant change in the manner in which rates are set by regulators
from cost-based regulation to another form of regulation.

The Securities and Exchange Commission has questioned the ability
of certain utility companies continuing the application of SFAS No. 71
where legislation provides for the transition to retail competition.
Deregulation of the price of electricity issues related to the
application of SFAS No. 71 and 101, as to when and how to discontinue
the application of SFAS No. 71 by utilities during transition to
competition has been referred to the Financial Accounting Standards
Board's Emerging Issues Task Force ("EITF").

The EITF has reached a tentative consensus, and no further
discussion is planned, that regulatory assets should be assigned to
separable portions of the Company's business based on the source of the
cash flows that will recover those regulatory assets. Therefore, if the
source of the cash flows is from a separable portion of the Company's
business that meets the criteria to apply SFAS No. 71, those regulatory
assets should not be written off under SFAS No. 101, "Accounting for the
Discontinuation of Application of SFAS No. 71," but should be assessed
under paragraph 9 of SFAS No. 71 for realizability.

SFAS No. 121, "Accounting for the Impairment of Long Lived Assets
and for Long-Lived Assets to Be Disposed Of," which was adopted by the
Company on January 1, 1996, requires that any assets, including
regulatory assets, that are no longer probable of recovery through
future revenues, be revalued based upon future cash flows. SFAS No. 121
requires that a rate-regulated enterprise recognize an impairment loss
for the amount of costs excluded from recovery. As of December 31,
1999, based upon the regulatory environment within which the Company
currently operates, SFAS No. 121 did not have an impact on the Company's
financial position or results of operations. Competitive influences or
regulatory developments may impact this status in the future.

Because the Company is unable to predict what form possible future
restructuring legislation will take, it cannot predict if or to what
extent SFAS Nos. 71 and 121 will continue to be applicable in the
future. In addition, if the Company is unable to mitigate or otherwise
recover stranded costs that could arise from any potentially adverse
legislation or regulation, the Company would have to assess the
likelihood and magnitude of losses incurred under its power contract
obligations.
As such, the Company cannot predict whether any restructuring
legislation enacted in Vermont or New Hampshire, once implemented, would
have a material adverse effect on the Company's operations, financial
condition or credit ratings. However, the Company's failure to recover
a significant portion of its purchased power costs, would likely have a
material adverse effect on the Company's results of operations, cash
flows, ability to obtain capital at competitive rates and ability to
exist as a going concern. It is possible that stranded cost exposure
before mitigation could exceed the Company's current total common stock
equity.

Inflation - The annual rate of inflation, as measured by the Consumer
Price Index, was 2.2% for 1999, 1.6% for 1998 and 1.7% for 1997. The
Company's revenues, however, are based on rate regulation that generally
recognizes only historical costs. Although the rate of inflation has
eased, it continues to have an impact on most aspects of the business.

Recent Accounting Pronouncements - In June 1997, the Financial
Accounting Standards Board ("FASB") issued SFAS No. 130, Reporting
Comprehensive Income, effective for fiscal years beginning after
December 15, 1997. SFAS No. 130 established standards for reporting and
display of comprehensive income and its components in a full set of
general-purpose financial statements. It requires that an enterprise
classify items of other comprehensive income by their nature in a
financial statement and display the accumulated balance of other
comprehensive income separately in the equity section of a statement of
financial position. In 1999 and 1998 the Company recognized a pre-tax
minimum pension liability adjustment of $0.4 million and $0.6 million,
respectively, or $0.1 million and $0.4 million net of tax, respectively.

In June 1998, the FASB issued SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities. In June 1999, the FASB
issued Statement No. 137, Accounting for Derivative Instruments and
Hedging Activities -- Deferral of the Effective Date of SFAS No. 133.
This Statement establishes accounting and reporting standards requiring
that every derivative instrument (including certain derivative
instruments embedded in other contracts) be recorded in the balance
sheet as either an asset or liability measured at its fair value. This
Statement requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a
derivative's gains and losses to offset related results on the hedged
item in the income statement, and requires that a company must formally
document, designate, and assess the effectiveness of transactions that
receive hedge accounting.

SFAS No. 133, as amended, is effective for fiscal years beginning
after June 15, 2000. A company may also implement this Statement as of
the beginning of any fiscal quarter after issuance (that is, fiscal
quarters beginning June 16, 1998 and thereafter). SFAS No. 133 cannot
be applied retroactively. SFAS No. 133 must be applied to (a)
derivative instruments and (b) certain derivative instruments embedded
in hybrid contracts. With respect to hybrid instruments, a company may
elect to apply SFAS 133, as amended, to (1) all hybrid contracts, (2)
only those hybrid instruments that were issued, acquired, or
substantively modified after December 31, 1997, or (3) only those hybrid
instruments that were issued, acquired, or substantively modified after
December 31, 1998. The Company has not yet quantified the impacts of
adopting SFAS No. 133 on the financial statements and has not determined
the timing or method of the adoption of SFAS No. 133.

Effective January 1, 1999, the Company adopted EITF No. 98-10,
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities. EITF Issue 98-10 requires energy trading contracts to be
recorded at fair value on the balance sheet, with the changes in fair
value included in earnings. In 1999, the Company recognized a net gain
of $.2 million in the accompanying Consolidated Statement of Income for
its open electricity purchase and sale commitments. As discussed in
Note 1, the Company decided to terminate its trading alliance with
Virginia Power during the third quarter of 1999 and the Company does not
intend to continue its trading operations following the maturity of its
remaining open contracts in 2000.

Forward Looking Statements - This document contains statements that are
forward looking. These statements are based on current expectations
that are subject to risks and uncertainties. Actual results will
depend, among other things, upon general economic and business
conditions, weather, the actions of regulators, including the outcome of
the litigation involving Connecticut Valley before the FERC and the
Court and the Company's pending rate case before the PSB and associated
appeal to the Vermont Supreme Court, as well as other factors which are
described in further detail in the Company's filings with the Securities
and Exchange Commission. The Company cannot predict the outcome of any
of these proceedings or other factors.

<PAGE>
Item 8. Financial Statements and Supplementary Data.

Index to Financial Statements and Supplementary Data

Page
No.

Report of Independent Public Accountants. . . . . . . . . . . 57

Financial Statements:

Consolidated Statement of Income for each of the
three years ended December 31, 1999 . . . . . . . . . . . 58

Consolidated Statement of Cash Flows for each of
the three years ended December 31, 1999 . . . . . . . . . 59

Consolidated Balance Sheet at December 31, 1999
and 1998 . . . . . . . . . . . . . . . . . . . . . . . . . 60

Consolidated Statement of Capitalization at
December 31, 1999 and 1998 . . . . . . . . . . . . . . . . 61

Consolidated Statement of Changes in Common Stock
Equity for each of the three years ended
December 31, 1999 . . . . . . . . . . . . . . . . . . . . 62

Notes to Consolidated Financial Statements . . . . . . . . 63

<PAGE>
Report of Independent Public Accountants
To the Board of Directors of
Central Vermont Public Service Corporation:

We have audited the accompanying consolidated balance sheet and
statement of capitalization of Central Vermont Public Service
Corporation and its wholly owned subsidiaries (the Company) as of
December 31, 1999 and 1998, and the related consolidated statements of
income, changes in common stock equity 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 audits.

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

In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Central
Vermont Public Service Corporation and its wholly owned subsidiaries as
of December 31, 1999 and 1998 and the results of their operations and
cash flows for each of the three years in the period ended December 31,
1999 in conformity with generally accepted accounting principles.

As discussed in Note 13, the Company has filed with the Federal
Energy Regulatory Commission a request for an exit fee mechanism to
cover the stranded costs resulting from the anticipated cancellation of
the power contract between the Company and its wholly owned subsidiary
Connecticut Valley. If the Company is unable to obtain an order
authorizing the recovery of a significant portion of the exit fee, or
other appropriate stranded cost mechanism, the Company would be required
to recognize a loss under this contract of a material amount. The
Company is also involved in related litigation in the federal courts.
Additionally, on October 27, 1998, the Company reached a settlement
agreement on rates with the Vermont Public Service Board (PSB). The
agreement incorporates a disallowance of a portion of the Company's
purchased power cost under its Hydro-Quebec contracts while the Vermont
Supreme Court is reviewing the Company's claim that the PSB is precluded
from again trying the Company on certain Hydro-Quebec contract issues.
If the ultimate resolution of these proceedings, including any
proceedings by the PSB subsequent to a Vermont Supreme Court decision,
is unfavorable to the Company, the result would have a significant
adverse impact on the Company and could impact the Company's financial
viability.

ARTHUR ANDERSEN LLP

Boston, Massachusetts
February 7, 2000 (except
with respect to the
matter discussed in
Note 13 as to which
the date is March 6, 2000).

<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF INCOME
(Dollars in thousands, except per share amounts)

Year Ended December 31
1999 1998 1997
<S> <C> <C> <C>
Operating Revenues $419,815 $303,835 $304,732
-------- -------- --------
Operating Expenses
Operation
Purchased power 269,386 184,887 171,443
Production and transmission 22,575 23,383 22,417
Other operation 46,967 44,110 40,909
Maintenance 17,613 15,613 15,333
Depreciation 16,955 16,708 16,931
Other taxes, principally property taxes 11,308 11,426 11,490
Taxes on income 10,360 (283) 7,573
-------- -------- --------
Total operating expenses 395,164 295,844 286,096
-------- -------- --------
Operating Income 24,651 7,991 18,636
Other Income and Deductions -------- -------- --------
Equity in earnings of affiliates 2,844 3,191 3,214
Allowance for equity funds during construction - 61 75
Other income, net 1,282 3,826 6,522
Provision for income taxes (35) (426) (1,590)
-------- -------- --------
Total other income and deductions, net 4,091 6,652 8,221
-------- -------- --------
Total Operating and Other Income 28,742 14,643 26,857
Interest Expense -------- -------- --------
Interest on long-term debt 10,651 9,868 9,337
Other interest 1,548 831 400
Allowance for borrowed funds during construction (41) (39) (31)
-------- -------- --------
Total interest expense, net 12,158 10,660 9,706
-------- -------- --------
Net Income Before Extraordinary Charge 16,584 3,983 17,151
Extraordinary Charge Net of Taxes - - 811
-------- -------- --------
Net Income 16,584 3,983 16,340
Preferred Stock Dividends Requirements 1,862 1,945 2,028
-------- -------- --------
Earnings Available For Common Stock $ 14,722 $ 2,038 $ 14,312
======== ======== ========

Average Shares of Common Stock Outstanding 11,463,197 11,439,688 11,458,735
Basic and Diluted Share of Common Stock:
Earnings before extraordinary charge $1.28 $ .18 $1.32
Extraordinary charge - - .07

Earnings Per Basic and Diluted Share of Common Stock $1.28 $ .18 $1.25

Dividends Paid Per Share of Common Stock $ .88 $ .88 $ .88

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

<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in thousands)
Year Ended December 31
1999 1998 1997
<S> <C> <C> <C>

Cash Flows Provided (Used)By:
Operating Activities
Net income $16,584 $ 3,983 $16,340
Adjustments to reconcile net income to net cash
provided by operating activities
Equity in earnings of affiliates (2,844) (3,191) (3,214)
Dividends received from affiliates 2,739 3,267 3,216
Equity in earnings from non-utility investments 795 (6,740) (5,378)
Distribution of earnings from non-utility
investments 4,390 4,744 4,403
Depreciation 16,955 16,708 16,931
Amortization of capital leases 1,093 1,082 1,081
Deferred income taxes and investment tax credits 1,971 (5,989) (6,529)
Extraordinary charge - - 1,198
Allowance for equity funds during construction - (61) (75)
Net deferral and amortization of nuclear
replacement energy and maintenance costs (4,914) (1,657) 4,913
Amortization of conservation & load management
costs 6,613 5,202 7,018
Net deferral and amortization of restructuring
costs - (1,075) -
Gain on sale of assets - - (4,986)
(Increase) decrease in accounts receivable and
unbilled revenues (11,138) (5,465) 855
Increase in accounts payable 3,315 6,543 668
Increase (decrease) in accrued income taxes (2,300) (3,656) 4,168
Change in other working capital items 588 (4,094) 3,532
Change in environmental reserve 68 6,848 591
Other, net (2,683) 5,294 (2,758)
------- ------- -------
Net cash provided by operating activities 31,232 21,743 41,974
------- ------- -------
Investing Activities
Construction and plant expenditures (13,231) (16,046) (13,841)
Conservation and load management expenditures (2,440) (2,208) (1,837)
Return of capital 186 233 233
Proceeds from sale of assets 88 - 6,374
Special deposit - 2,946 2,283
Non-utility investments (14,338) (3,046) (1,197)
Other investments, net (198) (251) 54
------- ------- -------
Net cash used for investing activities (29,933) (18,372) (7,931)
------- ------- -------
Financing Activities
Sale (repurchase) of common stock 75 494 (1,072)
Short-term debt, net (40,585) 24,350 (5,100)
Long-term debt, net 78,674 (20,520) (3,019)
Retirement of preferred stock (1,000) (1,000) (1,000)
Common and preferred dividends paid (11,950) (12,006) (12,630)
Reduction in capital lease obligations (1,092) (1,082) (1,081)
Other (11) (62) -
------- ------- -------
Net cash provided (used) for financing activities 24,111 (9,826) (23,902)
------- ------- -------
Net Increase (Decrease) In Cash and Cash Equivalents 25,410 (6,455) 10,141
Cash and Cash Equivalents at Beginning of Year 10,051 16,506 6,365
------- ------- -------
Cash and Cash Equivalents at End of Year $35,461 $10,051 $16,506
======= ======= =======
Supplemental Cash Flow Information
Cash paid during the year for:
Interest (net of amounts capitalized) $ 9,207 $10,267 $ 9,476
Income taxes (net of refunds) $10,935 $ 9,556 $10,654
Non-cash Operating, Investing and Financing Activities
Receivables purchase agreement (Note 10)
Regulatory assets (Notes 1,2 and 12)
Long-term lease arrangements (Note 14)

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

<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEET
(Dollars in thousands)
December 31
Assets 1999 1998
<S> <C> <C>

Utility Plant, at original cost $475,845 $469,204
Less accumulated depreciation 173,605 160,666
-------- --------
302,240 308,538
Construction work in progress 11,315 10,461
Nuclear fuel, net 1,177 948
-------- --------
Net utility plant 314,732 319,947
-------- --------
Investments and Other Assets
Investments in affiliates, at equity 25,501 26,142
Non-utility investments 45,269 35,896
Non-utility property, less accumulated depreciation 2,513 2,920
-------- --------
Total investments and other assets 73,283 64,958
-------- --------
Current Assets
Cash and cash equivalents 35,461 10,051
Special deposits 113 424
Accounts receivable, less allowance for uncollectible
accounts ($1,595 in 1999 and $2,242 in 1998) 38,381 29,224
Unbilled revenues 20,605 18,677
Materials and supplies, at average cost 3,126 3,746
Prepayments 1,964 1,881
Other current assets 6,510 9,768
-------- --------
Total current assets 106,160 73,771
-------- --------
Regulatory Assets 62,808 66,208
-------- --------
Other Deferred Charges 6,976 5,398
-------- --------
Total Assets $563,959 $530,282
======== ========
Capitalization And Liabilities
Capitalization
Common stock equity $184,021 $179,182
Preferred and preference stock 8,054 8,054
Preferred stock with sinking fund requirements 17,000 18,000
Long-term debt 155,251 90,077
Capital lease obligations 15,060 16,141
-------- --------
Total capitalization 379,386 311,454
-------- --------
Current Liabilities
Short-term debt - 37,000
Current portion of long-term debt 16,688 6,773
Accounts payable 14,843 11,589
Accounts payable - affiliates 12,311 11,784
Accrued income taxes 675 2,975
Dividends declared 2,523 2,521
Nuclear decommissioning costs 3,457 4,820
Disallowed purchased power costs 2,859 7,361
Other current liabilities 18,823 17,403
-------- --------
Total current liabilities 72,179 102,226
-------- --------
Deferred Credits
Deferred income taxes 48,631 47,581
Deferred investment tax credits 6,440 6,831
Nuclear decommissioning costs 18,548 23,239
Other deferred credits 38,775 38,951
-------- --------
Total deferred credits 112,394 116,602
-------- --------
Commitments and Contingencies
Total Capitalization and Liabilities $563,959 $530,282
======== ========

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

<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF CAPITALIZATION
(Dollars in thousands)

December 31
1999 1998
<S> <C> <C>
Common Stock Equity
Common stock, $6 par value, authorized 19,000,000
shares; issued 11,785,848 shares $ 70,715 $ 70,715
Other paid-in capital 45,340 45,318
Accumulated other comprehensive income (246) (365)
Treasury stock (319,043 shares and 324,717 shares,
respectively, at cost) (4,159) (4,234)
Retained earnings 72,371 67,748
-------- --------
Total common stock equity 184,021 179,182
-------- --------

Cumulative Preferred and Preference Stock
Preferred stock, $100 par value, authorized
500,000 shares
Outstanding:
Non-redeemable
4.15 % Series; 37,856 shares 3,786 3,786
4.65 % Series; 10,000 shares 1,000 1,000
4.75 % Series; 17,682 shares 1,768 1,768
5.375% Series; 15,000 shares 1,500 1,500
Redeemable
8.30 % Series; 170,000 shares 17,000 18,000
Preferred stock, $25 par value, authorized
1,000,000 shares
Outstanding - none - -
Preference stock, $1 par value, authorized
1,000,000 shares
Outstanding - none - -
-------- --------
Total cumulative preferred and preference stock 25,054 26,054
-------- --------
Long-Term Debt
First Mortgage Bonds
9.20 % Series FF, due 2000 7,500 7,500
9.26 % Series GG, due 2002 3,000 3,000
9.97 % Series HH, due 2003 15,000 18,000
8.91 % Series JJ, due 2031 15,000 15,000
5.54 % Series LL, due 2000 5,000 5,000
6.01 % Series MM, due 2003 7,500 7,500
6.27 % Series NN, due 2008 3,000 3,000
6.90 % Series OO, due 2023 17,500 17,500

Second Mortgage Bonds
8.125%, due 2004 75,000 -

Vermont Industrial Development Authority Bonds
Variable, due 2013 (3.90% at December 31, 1999) 5,800 5,800
New Hampshire Industrial Development Authority Bonds
6.40%, due 2009 5,500 5,500
Connecticut Development Authority Bonds
Variable, due 2015 (3.35% at December 31, 1999) 5,000 5,000
Other, various 7,139 4,050
-------- --------
171,939 96,850
Less current portion 16,688 6,773
-------- --------
Total long-term debt 155,251 90,077
-------- --------
Capital Lease Obligations 15,060 16,141
-------- --------
Total Capitalization $379,386 $311,454
======== ========

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

<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF CHANGES IN COMMON STOCK EQUITY
(Dollars in thousands)

Accumulated
Other Other
Common Stock Paid-in Comprehensive Treasury Retained
Shares Amount Capital Income Stock Earnings Total
------ ------ ------- ------------ -------- -------- --------

<S> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1996 11,519,748 $70,715 $45,273 - $(3,656) $74,137 $186,469
Treasury stock at cost (96,347) (1,072) (1,072)
Net income 16,340 16,340
Cash dividends on capital stock:
Common stock - $.88 per share (12,608) (12,608)
Cumulative preferred stock:
Non-redeemable (368) (368)
Redeemable (1,660) (1,660)
Amortization of preferred stock
issuance expenses 22 22
------- ----- ----- ----- ------ ------- -------
Balance, December 31, 1997 11,423,401 70,715 45,295 - (4,728) 75,841 187,123
Treasury stock at cost 37,730 494 494
Net income 3,983 3,983
Other comprehensive income net of taxes (365) (365)
Cash dividends on capital stock:
Common stock - $.88 per share (10,131) (10,131)
Cumulative preferred stock:
Non-redeemable (368) (368)
Redeemable (1,577) (1,577)
Amortization of preferred stock
issuance expenses 23 23
---------- ------- ------- ------- ------- -------- --------
Balance, December 31, 1998 11,461,131 70,715 45,318 (365) (4,234) 67,748 179,182

Treasury stock at cost 5,674 75 75
Net income 16,584 16,584
Other comprehensive income net of taxes 119 119
Cash dividends on capital stock
Common stock - $.88 per share (10,099) (10,099)
Cumulative preferred stock:
Non-redeemable (368) (368)
Redeemable (1,494) (1,494)
Amortization of preferred stock
issuance expenses 22 22
---------- ------- ------- ------- ------- ------- --------
Balance, December 31, 1999 11,466,805 $70,715 $45,340 (246) $(4,159) $72,371 $184,021
========== ======= ======= ======= ======= ======= ========

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1
Summary of significant accounting policies

Consolidation The consolidated financial statements include the accounts
of the Company and its wholly owned subsidiaries.

Regulation The Company is subject to regulation by the PSB, the NHPUC
and the FERC, with respect to rates charged for service, accounting and
other matters pertaining to regulated operations. As such, the Company
currently prepares its financial statements in accordance with SFAS
No. 71, "Accounting for the Effects of Certain Types of Regulation," for
both the Company's regulated Vermont service territory and FERC
regulated wholesale business. In order for a company to report under
SFAS No. 71, the Company's rates must be designed to recover its costs
of providing service, and the Company must be able to collect those
rates from customers. If rate recovery of these costs becomes unlikely
or uncertain, whether due to competition or regulatory action, these
accounting standards would no longer apply to the Company's regulated
operations. In the event the Company determines that it no longer meets
the criteria for applying SFAS No. 71, the accounting impact would be an
extraordinary non-cash charge to operations of an amount that could be
material. Criteria that give rise to the discontinuance of SFAS No. 71
include (1) increasing competition that restricts the Company's ability
to establish prices to recover specific costs, and (2) a significant
change in the manner in which rates are set by regulators from
cost-based regulation to another form of regulation. Management
periodically reviews these criteria to ensure the continuing application
of SFAS No. 71 is appropriate. Based on a current evaluation of the
various factors and conditions that are expected to impact future cost
recovery, management believes that its regulatory assets are probable of
future recovery in the state of Vermont for the Company's retail
business. However, such recovery of regulatory assets is not probable in
the state of Hew Hampshire for Connecticut Valley.

As a result of legal and regulatory actions described in Note 13
below, in 1998, management determined to discontinue the application of
regulatory accounting principles applied to Connecticut Valley. As such,
Connecticut Valley wrote off in 1998 regulatory assets of approximately
$1.3 million on a pre-tax basis. For additional information see Note 13
below.

Unregulated Business - The Company's two wholly owned non-regulated
subsidiaries, Catamount and SmartEnergy, results of operations are
included in Other income, net in the Other Income and Deductions section
of the Consolidated Statement of Income. Catamount's policy is to
expense all screening, feasibility and development expenditures.
Catamount's costs incurred subsequent to obtaining financial viability
are recognized as assets subject to depreciation or amortization in
accordance with industry practice. Project viability is obtained when
it becomes probable that costs incurred will generate future economic
benefits sufficient to recover these costs.

Revenues - Estimated unbilled revenues are recorded at the end of
accounting periods. For 1999 and 1998, operating revenues include
$100.1 million and $11.3 million related to the Virginia Power alliance
which was effectively terminated by the Company during the third quarter
of 1999.

Maintenance - Maintenance and repairs, including replacements not
qualifying as retirement units of property, are charged to maintenance
expense. Replacements of retirement units are charged to utility plant.
The original cost of units retired plus the cost of removal, less
salvage, is charged to the accumulated provision for depreciation.

Depreciation - The Company uses the straight-line remaining life method
of depreciation. Total depreciation expense was 3.54% of the cost of
depreciable utility plant for each of the years 1997 through 1999.
Income Taxes - In accordance with SFAS No. 109, "Accounting for Income
Taxes", the Company recognizes tax assets and liabilities for the
cumulative effect of all temporary differences between financial
statement carrying amounts and the tax basis of assets and liabilities.
Investment tax credits associated with utility plant are deferred and
amortized ratably to income over the lives of the related properties.
Investment tax credits associated with non-utility plant are recognized
as income in the year realized.

Allowance for Funds During Construction - Allowance for funds used
during construction or AFDC is the cost, during the period of
construction, of debt and equity funds used to finance construction
projects. The Company capitalizes AFDC as a part of the cost of major
utility plant projects to the extent that costs applicable to such
construction work in progress have not been included in rate base in
connection with rate-making proceedings. AFDC equity represents a
current non-cash credit to earnings which is recovered over the life of
the property. The AFDC rates used by the Company were 9.38%, 8.62% and
5.52% for the years 1997 through 1999, respectively.

Regulatory Assets - Certain costs are deferred and amortized in
accordance with authorized or expected rate-making treatment. The major
components of regulatory assets reflected in the Consolidated Balance
Sheet as of December 31, are as follows (dollars in thousands):

<TABLE>
<CAPTION>
1999 1998
---- ----
<S> <C> <C>
Conservation and load management $13,173 $15,611
Restructuring costs 3,757 5,087
Nuclear refueling outage costs 8,149 2,948
Income taxes 8,429 9,613
Year 2000 costs and technologies initiatives 2,766 2,204
Dismantling costs:
Maine Yankee nuclear power plant 12,785 15,228
Connecticut Yankee nuclear power plant 8,351 9,971
Yankee Atomic nuclear power plant 870 2,860
Hydro-Quebec arbitration costs 1,970 -
Unrecovered plant and regulatory study costs 1,700 1,875
Other regulatory assets 858 811
------- -------
$62,808 $66,208
======= =======
</TABLE>

The Company earns a return on the unamortized C&LM and replacement
energy and maintenance costs. During regular nuclear refueling outages,
the incremental costs attributable to replacement energy purchased from
NEPOOL and maintenance costs are deferred and amortized ratably to
expense until the next regularly scheduled refueling shutdown. The net
regulatory asset related to the adoption of SFAS No. 109 is recovered
through tax expense in the Company's cost of service generally over the
remaining lives of the related property. Recovery for the unamortized
dismantling costs for Yankee Atomic, Connecticut Yankee and Maine Yankee
is provided without a return on investment through mid-2000, 2007 and
2008, respectively. See Note 2 below for discussion of the costs
associated with the discontinued operations of the Yankee Atomic,
Connecticut Yankee and Maine Yankee nuclear power plants. In addition,
the Company is not earning a return on approximately $7.4 million of
restructuring, Year 2000 and other unamortized regulatory assets which
are being recovered over periods ranging from two to 33 years. Recovery
of $2.0 million of Hydro-Quebec arbitration costs will be determined in
the next rate proceeding.

Purchased Power - The Company records the annual cost of power obtained
under long-term contracts as operating expenses. Since these contracts,
as more fully described in Note 14, do not convey to the Company the
right to use property, plant, or equipment, they are considered
executory in nature. This accounting treatment is in contrast to the
Company's commitment with respect to the Hydro Quebec Phase I and II
transmission facilities which are considered capital leases. As such,
the Company has recorded a liability for its commitment under the
Phase I and II arrangements and recognized an asset for the right to use
these facilities. For 1999 and 1998 purchased power includes $100.6
million and $10.2 million related to the Virginia Power alliance which
was effectively terminated by the Company during the third quarter of
1999.

Valuation of Long-Lived Assets - The Company periodically evaluates the
carrying value of long-lived assets and long-lived assets to be disposed
of, including its investments in nuclear generating companies and its
interests in jointly owned generating facilities, when events and
circumstances warrant such a review. The carrying value of such assets
is considered impaired when the anticipated undiscounted cash flow from
such an asset is separately identifiable and is less than its carrying
value. In that event, a loss is recognized based on the amount by which
the carrying value exceeds the fair market value of the long-lived
asset. Based on management's estimates, no impairment of long-lived
assets exists as of December 31, 1999.

Use of Estimates - The preparation of financial statements in accordance
with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of
assets and liabilities, the disclosures of contingent assets and
liabilities and revenues and expenses. Actual results could differ from
those estimates.

Statement of Cash Flows - The Company considers all highly liquid
investments with a maturity of three months or less when acquired to be
cash equivalents.

Note 2
Investments in affiliates

The Company uses the equity method to account for its investments
in the following companies (dollars in thousands):

<TABLE>
<CAPTION>
December 31
Ownership 1999 1998
<S> <C> <C> <C>
Nuclear generating companies:
Vermont Yankee Nuclear Power Corporation 31.3% $16,745 $16,969
Connecticut Yankee Atomic Power Company 2.0% 2,097 2,094
Maine Yankee Atomic Power Company 2.0% 1,488 1,578
Yankee Atomic Electric Company 3.5% 549 690
------- -------
20,879 21,331
Vermont Electric Power Company, Inc.:
Common stock 56.8% 3,513 3,513
Preferred stock 1,109 1,298
------- -------
$25,501 $26,142
======= =======
</TABLE>
Each sponsor of the nuclear generating companies is obligated to
pay an amount equal to its entitlement percentage of fuel, operating
expenses (including decommissioning expenses) and cost of capital and is
entitled to a similar share of the power output of the plants. The
Company's entitlement percentages are identical to the ownership
percentages except that Vermont Yankee's entitlement percentage is 35%.
The Company is obligated to contribute its entitlement percentage of the
capital requirements of Vermont Yankee and Maine Yankee and has a
similar, but limited, obligation to Connecticut Yankee. The Company is
responsible for paying its entitlement percentage of decommissioning
costs for Vermont Yankee, Connecticut Yankee, Maine Yankee and Yankee
Atomic as follows (dollars in millions):

<TABLE>
<CAPTION>
CVPS
Total Share of
Date of Estimated CVPS Funded
Study Obligation Obligation
<C> <C> <C> <C>

Obligation
Nuclear generating companies:
Vermont Yankee 1993 $312.7 $109.4 $73.4
Maine Yankee 1998 $343.9 $6.9 $ 3.6
Connecticut Yankee 1996 $426.7 $8.5 $ 3.6
Yankee Atomic 1994 $370.0 $13.0 $ 5.4
</TABLE>

Vermont Yankee
Vermont Yankee's current decommissioning cost study is based on a
1994 site study. The FERC approved settlement agreement allowed $312.7
million, in 1993 dollars, as the estimated decommissioning cost. Based
on the study's assumed cost escalation rate of 5.4% per annum and an
expiration of the Plant's operating license in the year 2012, the
estimated current cost of decommissioning is $428.7 million and, at the
end of 2012, is approximately $816.6 million. The present value of the
pro rata portion of decommissioning costs recorded to date is $290.0
million of which the Company's share is $101.5 million.

On November 17, 1999, Vermont Yankee executed an Asset Purchase
Agreement with AmerGen Energy Co. The sale of the nuclear generating
plant would transfer responsibility for decommissioning the plant to the
new owner. Additionally, Vermont Yankee's current owners will make a
one-time payment currently estimated at $54.3 million to pre-pay the
plant's decommissioning fund at $312.7 million. In return, AmerGen will
assume full responsibility for all future operating costs and the
estimated $816.6 million price tag for decommissioning the plant at the
end of its operating license in 2012. The agreement is subject to
several conditions, including approvals or specific rulings by various
regulatory authorities. As such, execution of the agreement does not
provide assurance that the sale will occur. This agreement also
involves the Company entering into a contract to purchase a portion of
the power produced by this plant.

Maine Yankee
In 1997 the Maine Yankee's nuclear power plant was prematurely
retired from commercial operation. The Company relied on Maine Yankee
for less than 5% of its required system capacity. Future payments for
the closing, decommissioning and recovery of the remaining investment in
Maine Yankee are estimated to be approximately $715.0 million in 1998
dollars including a decommissioning obligation of $344.0 million.

On January 19, 1999, Maine Yankee and the active intervenors filed
an Offer of Settlement with the FERC which the FERC approved. As a
result, all issues raised in the FERC proceeding, including recovery of
anticipated future payments for closing, decommissioning and recovery of
the remaining investment in Maine Yankee are resolved. Also resolved
are the issues raised by the secondary purchasers, who purchased Maine
Yankee power through agreements with the original owners, by limiting
the amounts they will pay for decommissioning the Maine Yankee plant and
by settling other points of contention affecting individual secondary
purchasers. As a result, it is possible that the Company will not be
able to recover approximately $.5 million of these costs.

Connecticut Yankee
In 1996 the Connecticut Yankee Nuclear power plant was prematurely
retired from commercial operation. The Company relied on Connecticut
Yankee for less than 3.0% of its required system capacity.

On August 31, 1998, a FERC Administrative Law Judge recommended
that the owners of Connecticut Yankee, including the Company, may
collect from customers $350.0 million for decommissioning the
Connecticut Yankee Nuclear Power Plant rather than the $426.7 million
requested. The Administrative Law Judge ruling is subject to approval
by the FERC Commissioners. If approved, it is possible that the Company
would not be able to recover approximately $1.5 million of
decommissioning costs through the regulatory process.

Yankee Atomic
In 1992, the Yankee Atomic nuclear power plant was retired from
commercial operation. The Company relied on Yankee Atomic for less than
1.5% of its system capacity.

Maine Yankee, Connecticut Yankee and Yankee Atomic Decommissioning Costs
Presently, costs billed to the Company by Maine Yankee, Connecticut
Yankee and Yankee Atomic, including a provision for ultimate
decommissioning of the units, are being collected from the Company's
customers through existing retail and wholesale rate tariffs. The
Company's share of remaining costs with respect to Maine Yankee,
Connecticut Yankee and Yankee Atomic's decisions to discontinue
operation, including the costs in the table above, is estimated to be
$12.8 million, $8.4 million and $.9 million, respectively, at December
31, 1999. These amounts are subject to ongoing review and revisions and
are reflected in the accompanying balance sheet both as regulatory
assets and nuclear dismantling liabilities (current and non-current).

The decision to prematurely retire these nuclear power plants was
based on economic analyses of the costs of operating them compared to
the costs of closing them and incurring replacement power costs over the
remaining period of the plants' operating licenses. The Company
believes that based on the current regulatory process, its proportionate
share of Maine Yankee, Connecticut Yankee and Yankee Atomic
decommissioning costs will be recovered through the regulatory process
and, therefore, the ultimate resolution of the premature retirement of
the three plants has not and will not have a material adverse effect on
the Company's earnings or financial condition.

Nuclear Insurance
The Price-Anderson Act currently limits public liability from a
single incident at a nuclear power plant to $9.7 billion. Beyond that a
licensee is 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 $9.5 billion per incident by assessing
$88.1 million against each of the 108 reactor units that are currently
subject to the Program in the United States, 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. Currently the Company's interests in the nuclear
power units are such that it could become liable for an aggregate of
approximately $3.7 million of such maximum assessment per incident per
year.

Vermont Yankee
Summarized financial information for Vermont Yankee Nuclear Power
Corporation is as follows (dollars in thousands):

Earnings 1999 1998 1997
<S> <C> <C> <C>
Operating revenues $208,812 $195,249 $173,106
Operating income $14,932 $15,282 $13,961
Net income $6,471 $7,125 $6,834

Company's equity in net income $2,022 $2,218 $2,144
</TABLE>

<TABLE>
<CAPTION>
December 31
Investment 1999 1998
<S> <C> <C>
Current assets $ 45,824 $ 36,947
Non-current assets 639,718 598,927
-------- --------
Total assets 685,542 635,874

Less:
Current liabilities 46,886 32,250
Non-current liabilities 584,728 548,981
-------- --------
Net assets $ 53,928 $ 54,643
======== ========

Company's equity in net assets $ 16,745 $ 16,969
</TABLE>

Included in Vermont Yankee's revenues shown above are sales to the
Company of $58.6 million,$59.1 and $65.0 million for 1997 through 1999,
respectively. These amounts are reflected as purchased power, net of
deferrals and amortization, in the accompanying Consolidated Statement
of Income.

VELCO
Vermont Electric Power Company, Inc. ("VELCO") and its wholly owned
subsidiary Vermont Electric Transmission Company, Inc. own and operate
transmission systems in Vermont over which bulk power is delivered to
all electric utilities in the state. VELCO has entered into
transmission agreements with the state of Vermont and the electric
utilities and under these agreements bills all costs, including interest
on debt and a fixed return on equity, to the state and others using the
system. These contracts enable VELCO to finance its facilities
primarily through the sale of first mortgage bonds. Included in VELCO's
revenues shown below are transmission services to the Company (reflected
as production and transmission expenses in the accompanying Consolidated
Statement of Income) amounting to $8.7 million, $8.8 million and $8.6
million for 1997 through 1999, respectively.

VELCO operates pursuant to the terms of the 1985 Four-Party
Agreement (as amended) with the Company and two other major distribution
companies in Vermont. Although the Company owns 56.8% of VELCO's
outstanding common stock, the Four-Party Agreement effectively restricts
the Company's control of VELCO. Therefore, VELCO's financial statements
have not been consolidated. The Four-Party Agreement continued in full
force and effect until May 1995 and was extended for an additional
two-year term in May 1995, and every two years thereafter, unless at
least ninety (90) days prior to any two-year anniversary, any party
shall notify the other parties in writing that it desires to terminate
the agreement as of such anniversary. No such notification has been
filed by the parties. The Company also owns 46.6% of VELCO's
outstanding preferred stock, $100 par value.

Summarized financial information for VELCO is as follows (dollars in
thousands):

<TABLE>
<CAPTION>
Earnings 1999 1998 1997
<S> <C> <C> <C>
Transmission revenues $16,935 $17,268 $18,481
Operating income $ 2,633 $ 2,691 $ 2,773
Net income $ 1,221 $ 1,153 $ 1,213

Company's equity in net income $638 $581 $618
</TABLE>

<TABLE>
<CAPTION>
December 31
Investment 1999 1998
<S> <C> <C>
Current assets $19,289 $20,430
Non-current assets 48,005 47,228
------- -------
Total assets 67,294 67,658

Less:
Current liabilities 26,434 22,093
Non-current liabilities 32,297 36,597
------- -------
Net assets $ 8,563 $ 8,968
======= =======
Company's equity in net assets $ 4,622 $ 4,811
</TABLE>

Note 3
Non-utility investments

Catamount
The Company's wholly owned subsidiary, Catamount, invests through
its wholly owned subsidiaries, in non-regulated, energy-related projects
in Western Europe and North America. Catamount's earnings were $2.1
million, $3.3 million and $4.1 million for 1999, 1998 and 1997,
respectively. Earnings for 1997 reflect a net of tax gain of
approximately $1.8 million from the sale of NW Energy Williams Lake L.P.
Certain financial information for Catamount's investments is set forth
in the table that follows (dollars in thousands):

<TABLE>
<CAPTION> Investment
Generating In Service December 31
Projects Location Capacity Fuel Date Ownership 1999 1998
<S> <C> <C> <C> <C> <C> <C> <C>
Rumford Cogeneration Co. L.P. Maine 85MW Coal/Wood 1990 15.1% $14,358 $13,273
Ryegate Associates Vermont 20MW Wood 1992 33.1% 6,391 6,305
Appomattox Cogeneration L.P. Virginia 41MW Coal/Biomass 1982 25.3% 4,244 4,079
Black liquor
Rupert Cogeneration Partners, Ltd. Idaho 10MW Gas 1996 50.0% 1,826 1,775
Glenns Ferry Cogeneration Partners, Ltd. Idaho 10MW Gas 1996 50.0% 1,529 1,387
Fibrothetford Limited Thetford, England 38.5MW Biomass 1998 44.0% 7,757 8,556
Heartlands Power Limited Fort Dunlop, England 98MW Gas 1999 50.0% 7,030 421
------- -------
$43,135 $35,796
===== =====
</TABLE>

On December 21,1999 Catamount invested $.4 million to purchase a
50% interest in Heartlands Power Limited ("Heartlands"). Heartlands was
formed by Rolls-Royce Power Ventures to develop, construct and own a
98MW natural gas-fired power station in Fort Dunlop, England. Catamount
also loaned the project $6.6 million. Catamount currently has a
$1.2 million letter of credit outstanding to support certain of its
obligations in connection with a debt service requirement in the
Appomattox Cogeneration project and aggregated letters of credit of
$11.0 million in support of construction and equity commitments for its
Gauley River Power project. The Company currently owns 100% of the
Gauley River Power project, however, as a result of regulatory
requirements to reduce its ownership to a non-controlling level in order
to meet Qualifying Facility status following completion of the project,
this investment has not been consolidated in the accompanying financial
statements as the Company's control is considered temporary.
SmartEnergy
Another wholly owned subsidiary of the Company, SmartEnergy,
invests in unregulated energy and service related businesses, including
its 70% ownership interest in HSS. Overall, SmartEnergy incurred net
losses of $2.9 million, $1.5 million and $.7 million for 1999, 1998 and
1997, respectively.

HSS establishes a network of affiliate contractors who perform home
maintenance, repair and improvement needs via membership. Although
SmartEnergy owns a 70% interest in HSS, this investment is accounted for
using the equity method on the basis that financing plans will be
completed in early 2000 which will have the effect of diluting
SmartEnergy's ownership to a less than 50% level. HSS is seeking equity
investors to finance the national rollout of this business. HSS began
operations in 1999 and is subject to risks and challenges similar to a
company in the early stage of development. HSS' pre-tax loss for 1999
was $7.1 million, of which SmartEnergy's share is $5.3 million. As of
December 31, 1999, SmartEnergy has a net investment of $2.1 million.

Note 4
Common Stock

Through a common stock repurchase program which was suspended in
1997, the Company purchased from time to time 362,447 shares of its
common stock in open market transactions at an average price of $13.04
per share. These transactions, net of 43,404 shares sold in connection
with the Company's stock option plans, are recorded as treasury stock,
at cost, in the Company's Consolidated Balance Sheet.

Note 5
Redeemable preferred stock

The 8.30% Dividend Series Preferred Stock is redeemable at par
through a mandatory sinking fund in the amount of $1.0 million per
annum, and at its option, the Company may redeem at par an additional
non-cumulative $1.0 million per annum. Since the Company's redeemable
preferred stock was issued in a private placement, it is not practicable
to estimate the fair value.

Note 6
Stock Option Plans

The Company has issued stock to key employees and non-employee
directors under various option plans approved in 1988, 1993, 1997 and
1998 which authorize the granting of options with respect to 1,025,875
shares of the Company's common stock. Options are granted at prices not
less than 100% of the fair market value at the date of the option grant.
Shares available for future grants under the 1997 and 1998 stock option
plans were 107,890 at December 31, 1999. No additional grants may be
given under the 1988 and 1993 plans. Option activity during the past
three years was as follows:
<TABLE>
<CAPTION>
Average
Option Stock
Price Options

<S> <C> <C>
Options outstanding at December 31, 1996 $18.1271 299,975

Options exercised - -
Options granted 10.9900 126,750
Options expired 20.5416 (10,500)
-------- -------
Options outstanding at December 31, 1997 15.8928 416,225

Options exercised 11.6505 (34,475)
Options granted 14.6286 154,500
Options expired 24.3750 (20,250)
-------- -------
Options outstanding at December 31, 1998 15.4649 516,000

Options exercised 10.9375 (2,250)
Options granted 10.5742 95,860
Options expired 18.0476 (24,750)
-------- -------
Options outstanding at December 31, 1999 $14.5714 584,860
======== =======
</TABLE>

The price range of options outstanding at December 31, 1999 is
$10.5625 to $24.3125. The weighted average remaining contractual life
at December 31, 1999 is 6.69 years and the weighted average exercise
price is $14.5513. Exercisable options at December 31,1999 total
474,610 and the weighted average exercise price is $13.5854.

The Company accounts for these plans under Accounting Principles
Board Opinion No. 25, under which no compensation cost has been
recognized. Under SFAS No. 123, "Accounting for Stock-Based
Compensation," all awards granted must be recognized in compensation
cost. Had compensation cost for these plans been determined consistent
with SFAS No. 123, the Company's net income and earnings per share of
common stock would have been reduced to the following pro forma amounts
as follows(dollars in thousands, except per share amounts):

<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
<S> <C> <C> <C> <C>
Net Income As reported $16,584 $3,983 $16,340
Pro forma 16,518 $3,930 $16,309

Earnings per share
of common stock As reported $1.28 $.18 $1.25
Pro forma $1.27 $.17 $1.25
</TABLE>

The Company chose the Binomial model to project an estimate of
appreciation of the underlying shares of the stock during the respective
option term. The average assumptions used were as follows:
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Volatility .2982 .1861 .1808
Risk free rate of return 5.50% 6.25% 6.50%
Dividend yield 7.26% 6.57% 7.13%
Expected life in years 5-10 5-10 5-10
</TABLE>
Note 7
Long-term debt and sinking fund requirements

Utility

On July 30, 1999 the Company sold $75.0 million aggregate principal
amount of 8 1/8% Second Mortgage Bonds due 2004 at a price of 99.915%.

The Company and its subsidiaries' long-term debt contains financial
and non-financial covenants. At December 31, 1999 the Company and its
subsidiaries were in compliance with all debt covenants related to its
various debt agreements.

Based on outstanding debt at December 31, 1999, the aggregate
amount of long-term debt maturities and sinking fund requirements are
$16.7 million, $4.2 million, $7.2 million, $16.1 million and $75.2
million for the years 2000 through 2004, respectively. Substantially
all utility property and plant is subject to liens under the First and
Second Mortgage Bonds.

Non-Utility

On November 12, 1998, Catamount replaced its $8.0 million credit
facility with a $25.0 million revolving credit/term loan facility
maturing November 2006 which provides for up to $25.0 million in
revolving credit loans and letters of credit. This facility has a
security interest in Catamount's assets. Currently, a $1.2 million
letter of credit is outstanding to support certain of Catamount's
obligations in connection with a debt reserve requirement in the
Appomattox Cogeneration project and aggregated letters of credit of
$11.0 million in support of construction and equity commitments for its
Gauley River Power project.

SmartEnergy Water Heating Services, Inc., a wholly owned subsidiary
of SmartEnergy, has a secured seven-year term loan with Bank of New
Hampshire with an outstanding balance of $1.3 million at December 31,
1999. The interest rate is fixed at 9.25% per annum.

Financial obligations of the Company's subsidiaries are
non-recourse to the Company.

Note 8
Short-term debt

Utility

The Company had no short-term debt outstanding at December 31, 1999
and had $37.0 million at December 31, 1998 at average interest rate of
5.94%.

The Company had a $50.0 million revolving credit facility with a
group of banks which matured and was repaid in 1999. $25.0 million of
this facility was outstanding at December 31, 1998. The Company has an
aggregate of $16.9 million of letters of credit with termination dates
that have been extended to May 31, 2000. These letters of credit are
subject to a first mortgage interest in the same collateral supporting
the Company's first mortgage bonds. In addition, the Company had a
$12.0 million accounts receivable facility which was repaid by the
Company in November 1999.

Note 9
Financial instruments

The estimated fair values of the Company's financial instruments at
December 31, 1999 and 1998 are as follows (dollars in thousands):

1999 1998
------------------- ------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
--------- -------- -------- ---------
Long-term debt $171,939 $160,419 $96,850 $101,776

The carrying amount for cash and cash equivalents and short-term
debt approximates fair value because of the short maturity of those
instruments. The fair value of the Company's long-term debt is
estimated based on the quoted market prices for the same or similar
issues or on the current rates offered to the Company for debt of the
same remaining maturation.

The Company believes that any excess or shortfall in the fair value
relative to the carrying value of the Company's financial instruments,
if they were settled at amounts approximating those above, would not
result in a material impact on the Company's financial position or
results of operations.
Note 10
Receivables purchase agreement

Pursuant to SFAS No. 125, "Accounting for Transfers and Servicing
of Financial Assets and Extinguishments of Liabilities," the Company
classified amounts transferred under its receivable purchase agreement
as secured borrowings. The facility matured and was repaid on November
29, 1999. Those amounts related to the accounts receivable facility are
shown at December 31, 1998 as short-term debt.

Note 11
Pension and postretirement benefits

The Company has a non-contributory trusteed pension plan covering
all employees (union and non-union). Under the terms of the pension
plan, employees are generally eligible for monthly benefit payments upon
reaching the age of 65 with a minimum of five years of service. The
Company's funding policy is to contribute, at least, the statutory
minimum to a trust. The Company is not required by its union contract
to contribute to multi-employer plans.

The following table sets forth the funded status of the pension
plan and amounts recognized in the Company's Consolidated Balance Sheet
and Statement of Income (dollars in thousands):

December 31
1999 1998
<S> <C> <C>
Projected benefit obligation $54,172 $63,095
Fair value of plan assets (primarily equity
and fixed income securities) 79,834 65,602
Projected benefit obligation less ------- -------
than fair value of plan assets (25,662) (2,507)
Unrecognized net transition obligation 728 647
Unrecognized prior service costs (2,084) (2,681)
Unrecognized net gain 35,961 15,561
------- -------
Accrued pension liability $ 8,943 $11,020
======= =======
</TABLE>

<TABLE>
<CAPTION>
1999 1998 1997
<C> <C> <C>
Net pension costs include the following components
Service cost $ 1,854 $ 1,802 $ 1,802
Interest cost 4,035 4,459 4,307
Expected return on plan assets (5,081) (4,720) (4,756)
Net amortization and deferral 45 778 140
-------- ------- -------
Pension costs 853 2,319 1,493
Less amount allocated to other accounts 107 228 249
------- ------- -------
Net pension costs expensed $ 746 $ 2,091 $ 1,244
======= ======= =======
</TABLE>

Assumptions used in calculating pension cost were as follows:

<TABLE>
<CAPTION>
December 31
1999 1998
<S> <C> <C>
Weighted average discount rates 7.75% 6.75%
Expected long-term return on assets 9.25% 9.50%
Rate of increase in future compensation levels 4.50% 4.00%
</TABLE>

The Company sponsors a defined benefit postretirement medical plan
that covers all employees who retire with ten years or more of service
after age 45. The Company funds this obligation through a Voluntary
Employees' Benefit Association and 401(h) Subaccount in its Pension
Plan.

The following table sets forth the plan's funded status and amounts
recognized in the Company's Consolidated Balance Sheet and Statement of
Income in accordance with SFAS No. 106 (dollars in thousands):

<TABLE>
<CAPTION>
December 31
1999 1998
<S> <C> <C>
Accumulated postretirement benefit obligation $11,545 $10,757
Unrecognized transition obligation (3,326) (3,582)
Unrecognized net loss (2,112) (1,329)
------ -------
Accrued postretirement benefit cost 6,107 5,846
Less regulatory asset for restructuring costs 1,370 1,954
Effective accrued postretirement benefit ------ -------
costs $ 4,737 $ 3,892
======= =======
</TABLE>

<TABLE>
<CAPTION>
1999 1998 1997
<S> <C> <C> <C>
Net postretirement benefit cost includes the
following components
Service cost $ 214 $ 194 $ 197
Interest cost 892 815 716
Expected return on plan assets (87) (160) (145)
Amortization of transition obligation over
a twenty-year period, of regulatory asset and of
net actuarial loss 843 837 408
------ ------ ------
Effective postretirement benefit cost 1,862 1,686 1,176
Less amount allocated to other accounts 171 209 192
------ ------ ------
Net postretirement benefit cost expensed $1,691 $1,477 $ 984
====== ====== ======
</TABLE>

Assumptions used in the per capita costs of the accumulated
postretirement benefit obligation were as follows:

<TABLE>
<CAPTION> December 31
1999 1998
<S> <C> <C>
Per capita percent increase in health care costs:
Pre-65 6.50% 6.50%
Post-65 5.50% 5.50%
Weighted average discount rates 7.75% 6.75%
Rate of increase in future compensation levels 4.50% 4.00%
Long-term return on assets 8.50% 8.50%
</TABLE>

Health care costs are assumed to decrease to 6.0% for people under
65 years of age for the year 2001 and thereafter and remain at 5.5% for
people over 65 years of age for the year 2000 and thereafter.

Increasing (decreasing) the assumed health care cost trend rates by
one percentage point in each year would have resulted in an increase
(decrease) of $657,000 and $(563,000), respectively, in the accumulated
postretirement benefit obligation as of December 31, 1999, and an
increase (decrease) of about $45,000 and $(39,000), respectively, in the
aggregate of the service cost and interest cost components of net
periodic postretirement benefit cost for 1999.

The Company provides postemployment benefits consisting of
long-term disability benefits. The accumulated postemployment benefit
obligation at December 31, 1999 and 1998 of $.8 million and
$.7 million, respectively, is reflected in the accompanying Consolidated
Balance Sheet as a liability and is offset by a corresponding regulatory
asset of $.3 million for 1999 and $.5 million for 1998. The PSB in its
October 31, 1994 Rate Order allowed the Company to recover the
regulatory asset over a 7-1/2 year period beginning November 1, 1994
through April 30, 2002. The post-employment benefit costs charged to
expense in 1999, 1998 and 1997, including insurance premiums, were
$281,000, $118,000 and $247,000, respectively (pre-tax).

In the third quarter of 1997, the Company offered and recorded
obligations related to a voluntary retirement and severance programs to
employees. The estimated benefit obligation for the retirement program
as of December 31, 1999 is approximately $2.8 million. This amount
consists of pension benefits and post-retirement medical benefits of
$1.4 million and $1.4 million, respectively. The estimated benefit
obligation for the severance program which included termination pay as
well as other costs, is about $1.0 million as of December 31, 1999.
These obligations, deferred pursuant to a PSB Accounting Order dated
September 30, 1997, are reflected in the accompanying Consolidated
Balance Sheet both as regulatory assets and deferred credits. The
unamortized balance of approximately $3.8 million at December 31, 1999
will be amortized through December 31, 2002.

Note 12
Income taxes

The components of Federal and state income tax expense are as
follows (dollars in thousands):

<TABLE>
<CAPTION>
Year Ended December 31
1999 1998 1997
<S> <C> <C> <C>
Federal:
Current $ 6,760 $ 5,072 $12,277
Deferred 1,587 (4,376) (5,420)
Investment tax credits, net (391) (391) (391)
------- ------- -------
7,956 305 6,466
------- ------- -------
State:
Current 1,664 1,060 3,027
Deferred 775 (1,222) (718)
------- ------- -------
2,439 (162) 2,309
------- ------- -------
Total Federal and state income taxes $10,395 $ 143 $ 8,775
======= ======= =======
Federal and state income taxes charged to:
Operating expenses $10,360 $ (283) $ 7,573
Other income 35 426 1,590
Extraordinary item - - (388)
------- ------- -------
$10,395 $ 143 $ 8,775
======= ======= =======
</TABLE>

The principal items comprising the difference between the total
income tax expense and the amount calculated by applying the statutory
Federal income tax rate to income before tax are as follows (dollars in
thousands):

Year Ended December 31
1999 1998 1997
<S> <C> <C> <C>
Income before income tax $26,979 $4,126 $25,115
Federal statutory rate 35% 35% 35%
Federal statutory tax expense $ 9,443 $1,444 $8,790
Increases (reductions) in taxes resulting
from:
Dividend received deduction (790) (880) (884)
Deferred taxes on plant 453 348 283
State income taxes net of Federal tax
benefit 1,568 (105) 1,501
Investment credit amortization (391) (391) (391)
Other 112 (273) (524)
------- ------ ------
Total income tax expense provided $10,395 $ 143 $8,775
======= ====== ======
</TABLE>

Tax effects of temporary differences and tax carry forwards that
give rise to significant portions of the deferred tax assets and
deferred tax liabilities are presented below (dollars in thousands):

<TABLE>
<CAPTION>
Year Ended December 31
1999 1998 1997
<S> <C> <C> <C>
Deferred tax assets
Purchased power accrual $ 1,603 $ 3,695 $ 1,925
Accruals and other reserves not
currently deductible 6,668 7,575 4,818
Deferred compensation and pension 5,402 4,295 3,655
Environmental costs accrual 4,249 3,905 1,805
------- ------- -------
Total deferred tax assets 17,922 19,470 12,203
------- ------- -------
Deferred tax liabilities
Property, plant and equipment 50,164 51,680 51,819
Net regulatory asset 3,485 3,974 4,301
Conservation and load management
expenditures 5,445 6,453 6,713
Nuclear refueling costs 3,313 1,219 534
Other 4,146 3,725 2,832
------- ------- -------
Total deferred tax liabilities 66,553 67,051 66,199
------- ------- -------
Net deferred tax liability $48,631 $47,581 $53,996
======= ======= =======
</TABLE>

The Company received an accounting order from the PSB dated
September 30, 1997. This accounting order authorized the Company to
defer and amortize over a 20-year period beginning January 1, 1998,
approximately $2.0 million to reflect the revenue requirement level of
additional deferred income tax expense resulting from the enacted
Vermont Corporate income tax increase from 8.25% to 9.75% in 1997.

A valuation allowance has not been recorded, as the Company expects
all deferred income tax assets will be realized in the future.

Note 13
Retail Rates

The Company recognizes that adequate and timely rate relief is
necessary if it is to maintain its financial strength, particularly
since Vermont regulatory rules do not allow for changes in purchased
power and fuel costs to be automatically passed on to consumers through
rate adjustment clauses. The Company intends to continue its practice
of periodically reviewing costs and requesting rate increases when
warranted.

Vermont Retail Rate Proceedings: The Company filed for a 6.6%, or
$15.4 million per annum, general rate increase on September 22, 1997 to
become effective June 6, 1998 to offset increasing costs of providing
service. Approximately $14.3 million or 92.9% of the rate increase
request was to recover scheduled contractual increases in the cost of
power the Company purchases from Hydro-Quebec. At the same time, the
Company also filed a request to eliminate the winter-summer rate
differential and price electricity the same year-round.

In response to the Company's filing, the PSB decided to appoint an
independent investigator to examine the Company's decision to buy power
from Hydro-Quebec. The Company made a filing with the PSB stating that
the PSB as well as other parties should be barred from reviewing past
decisions because the PSB already examined the Company's decision to buy
power from Hydro-Quebec in a 1994 rate case in which the Company was
penalized for "improvident power supply management". During February
1998, the DPS filed testimony in opposition to the Company's retail rate
increase request. The DPS recommended that the PSB instead reduce the
Company's then current retail rates by 2.5% or $5.7 million. The
Company sought, and the PSB granted, permission to stay this rate case
and to file an interlocutory appeal of the PSB's denial of the Company's
motion to preclude a re-examination of the Company's Hydro-Quebec
contract in 1991. The Company has argued its position before the VSC.
The VSC has not yet rendered a decision and it is uncertain at this time
when a decision is forthcoming.

The Company filed on June 12, 1998 with the PSB for a 10.7% retail
rate increase that supplanted the September 22, 1997, 6.6% rate increase
request, to be effective March 1, 1999. On October 27, 1998, the Company
reached an agreement with the DPS regarding the June 1998 retail rate
increase request providing for a temporary rate increase in the
Company's Vermont retail rates of 4.7% or $10.9 million on an annualized
basis beginning with service rendered on or after January 1, 1999. The
agreement was approved by the PSB on December 11, 1998.

The 4.7% rate increase is subject to retroactive or prospective
adjustment upon future resolution of issues arising under the VJO Power
Contract presently before the VSC. The agreement temporarily disallows
approximately $7.4 million for the Company's purchased power costs under
the VJO Power Contract pending resolution of the issues before the VSC.
As a result of the 4.7% rate increase agreement, during the fourth
quarter of 1998 and 1999, the Company recorded pre-tax losses of $7.4
million and $2.9 million for disallowed purchased power costs,
representing the Company's estimated under recovery of power costs,
prior to further resolution, under the VJO Power Contract for calendar
year 1999 and the first quarter of year 2000, respectively. If in the
future, the Company is unable to increase rates to recover the temporary
disallowed purchased power costs prior to further resolution under the
VJO power contract or otherwise mitigate these costs, the Company would
be required to record losses for any estimated future under recovery.
At this time, the Company does not believe that such a loss is probable.

These temporary disallowances were calculated using comparable
methodology to that used by the PSB in the GMP rate case on February 28,
1998. In that case, the PSB found GMP's decision to commit to the VJO
Power Contract in 1991 "imprudent" and that power purchased under it was
not "used and useful." As a result, the PSB concluded that a portion of
GMP's current costs should not be imposed on GMP's customers and were
disallowed. GMP is appealing that rate order to the VSC. Should the
Company receive a similar order from the PSB, the Company would
experience a material adverse effect on its results of operations and
financial condition.

Assuming an unfavorable VSC ruling and depending on the methodology
to determine the amount of any permanent disallowance, its future impact
could be more or less than the 1999 $7.4 million temporary disallowance
or the 1999 $2.9 million first quarter 2000 temporary disallowance. If
the Company receives an unfavorable ruling from the VSC and the PSB
subsequently issues a final rate order adopting the disallowance
methodology used to determine the temporary Hydro-Quebec disallowance
described above for the duration of the VJO Power Contract, the Company
would not be able to recover approximately $198.2 million of power costs
over the life of the contract, including $11.5 million in 2000, $11.6
million in 2001, $11.8 million in 2002, $11.9 in million 2003 and $12.1
million in 2004. In such an event, the Company would be required to take
an immediate charge to earnings of approximately $198.2 million
(pre-tax). Such an outcome could jeopardize the Company's ability to
continue as a going concern.

New Hampshire Retail Rate/Federal Court Proceedings

Connecticut Valley retail rate tariffs, approved by the NHPUC,
contain a FAC, and a PPCA. Under these clauses, Connecticut Valley
recovers its estimated annual costs for purchased energy and capacity
which are reconciled when actual data is available.

On April 7, 1997, the NHPUC issued an Order addressing certain
threshold procedural matters raised in motions for rehearing and/or
clarification filed by various parties, including Connecticut Valley,
relative to the Final Plan and interim stranded cost orders. The
April 7, 1997 Order stayed those aspects of the Final Plan that were the
subject of rehearing or clarification requests and also stayed the
interim stranded cost orders for the various parties, including
Connecticut Valley. As such, those matters pertaining to the power
contract between Connecticut Valley and the Company were stayed. The
suspension of these orders was to remain in effect until two weeks
following the issuance of any order concerning outstanding requests for
rehearing and clarification.

In an Order dated December 31, 1997 in Connecticut Valley's FAC and
PPCA docket, the NHPUC found Connecticut Valley acted imprudently by not
terminating the wholesale contract between Connecticut Valley and the
Company, notwithstanding the stays of its February 28, 1997 Orders. The
NHPUC Order further directed Connecticut Valley to freeze its current
FAC and PPCA rates (other than short term rates to be paid to certain
Qualifying Facilities) effective January 1, 1998, on a temporary basis,
pending a hearing to determine: 1) the appropriate proxy for a market
price that Connecticut Valley could have obtained if it had terminated
its wholesale contract with the Company; 2) the implications of allowing
Connecticut Valley to pass on to its customers only that market price;
and 3) whether the NHPUC's final determination on the FAC and PPCA rates
should be reconciled back to January 1, 1998 or some other date.

On January 19, 1998, Connecticut Valley and the Company filed with
the Court for a temporary restraining order to maintain the status quo
ante by staying the NHPUC Order of December 31, 1997 and preventing the
NHPUC from taking any action that (i) compromises cost-based rate making
for Connecticut Valley; (ii) interferes with FERC's exclusive
jurisdiction over the Company's pending application to recover wholesale
stranded costs upon termination of its wholesale power contract with
Connecticut Valley; or (iii) prevents Connecticut Valley from recovering
through retail rates the stranded costs and purchased power costs that
it incurs pursuant to its FERC-authorized wholesale rate schedule with
the Company.

Based on the December 31, 1997 NHPUC Order as well as the NHPUC's
February 23, 1998 announcement, which resulted in the establishment of
Connecticut Valley's rates on a non cost-of-service basis, Connecticut
Valley no longer qualified, as of December 31, 1997, for the application
of SFAS No. 71. As a result, Connecticut Valley wrote-off all of its
regulatory assets associated with its New Hampshire retail business as
of December 31, 1997. This write-off amounted to approximately $1.2
million on a pre-tax basis. In addition, Connecticut Valley recorded a
$5.5 million pre-tax loss in 1997 for disallowed power costs.

On March 20, 1998, the NHPUC issued an order which affirmed,
clarified and modified various generic policy statements including the
reaffirmation to establish rates on the basis of a regional average
announced previously in its February 28, 1997 Order. The March 20, 1998
Order also addressed all outstanding motions for rehearings or
clarification relative to the policies or legal positions articulated in
the Final Plan and removed the stay covering the Company's interim
stranded cost order of April 7, 1997. In addition, the March 20, 1998
Order imposed various compliance filing requirements.

On April 3, 1998, the Court held a hearing on the Companies' motion
for a TRO and Preliminary Injunction against the NHPUC at which time
both the companies and the NHPUC presented arguments. In an oral ruling
from the bench, and in a written order issued on April 9, 1998, the
Court concluded that the companies had established each of the
prerequisites for preliminary injunctive relief and directed and
required the NHPUC to allow Connecticut Valley to recover through retail
rates all costs for wholesale power requirements service that
Connecticut Valley purchases from the Company pursuant to its
FERC-authorized wholesale rate schedule effective January 1, 1998 until
further court order. Connecticut Valley received an order from the
NHPUC authorizing retail rates to recover such costs beginning in May
1998. On April 14, 1998, the NHPUC filed a notice of appeal and a
motion for a stay of the Court's preliminary injunction. The NHPUC's
request for a stay was denied. At the same time, the NHPUC permitted
Connecticut Valley to recover in rates the full cost of its wholesale
power purchases from the Company.

Also, on April 3, 1998, the Court indicated its earlier TRO
enjoining the NHPUC's restructuring orders applied to Connecticut Valley
and prohibits the enforcement of the restructuring orders until the
Court conducts a consolidated hearing and rules on the requests for
permanent injunctive relief by plaintiff PSNH and the other utilities
that had been allowed to intervene in these proceedings, including the
Company and Connecticut Valley. The plaintiffs-intervenors thereafter
filed a motion asking the Court to extend its stay of action by the
NHPUC to implement restructuring and to make clear that the stay
encompasses the NHPUC's order of March 20, 1998.

As a result of these Court orders, Connecticut Valley's 1997
charges, described above, were reversed in the first quarter of 1998.
Combined, the reversal of these charges increased 1998 net income and
earnings per share of common stock by approximately $4.5 million and
$.39, respectively.

On April 1, 1998, the Bank notified Connecticut Valley that it was
in default of the Loan Agreement between the Bank and Connecticut Valley
dated December 27, 1994 and that the Bank would exercise all of its
remedies from and after May 5, 1998 in the event that the violations
were not cured. After reversing the 1997 write-offs described above,
Connecticut Valley was in compliance with the financial covenants
associated with its $3.75 million loan with the Bank. As a result,
Connecticut Valley satisfied the Bank's requirements for curing the
violation.

On June 5, 1998, the Court issued an Order which denied the NHPUC's
motion for a stay of the Court's preliminary injunction. The Order
clearly stated that no restructuring effort in New Hampshire can move
forward without the Court's approval unless all New Hampshire utilities
agree to the plan. The Order suspended all involuntary restructuring
efforts for all New Hampshire utilities until a hearing on the merits
was conducted. The NHPUC appealed this Order to the Court of Appeals.

On November 24, 1998, Connecticut Valley filed with the NHPUC its
annual FAC/PPCA rates to be effective January 1, 1999. On January 4,
1999, the NHPUC issued an Order allowing Connecticut Valley to implement
the proposed FAC rate of $.008 per kWh and the proposed PPCA rate of
$.01000 per kWh, on a temporary basis, effective on all bills rendered
on or after January 1, 1999. In addition, the NHPUC also ordered
Connecticut Valley to pay refunds plus interest to its retail customers
for any overcharges collected as a result of the April 9, 1998 Federal
District Court Order, should it be overturned or modified, which are
included in the estimated total losses of $4.3 million discussed below.

Connecticut Valley and the Company then requested the Court of
Appeals to stay the issuance of its mandate until the companies could
file a petition of certiorari to the United States Supreme Court and the
Supreme Court acted on the petition.

On January 22, 1999, the Court of Appeals denied the request.
However, the Court of Appeals granted a 21-day stay to enable the
Company to seek a stay pending certiorari from the Circuit Justice of
the Supreme Court. On February 11, 1999, the Company and Connecticut
Valley filed a petition for a writ of certiorari with the United States
Supreme Court and a motion to stay the effect of the Court of Appeals'
decision while the case was pending in the Supreme Court. The motion
for a stay was addressed to Justice Souter who is responsible for such
motions pertaining to the Court of Appeals for the First Circuit. On
February 18, 1999, Justice Souter denied the stay pending the petition
for certiorari and on April 19, 1999 the Supreme Court denied the
petition for certiorari.

As a result of legal and regulatory actions discussed above,
Connecticut Valley no longer qualified as of December 31, 1998 for the
application of SFAS No. 71, and wrote-off in the fourth quarter of 1998
all its regulatory assets associated with its New Hampshire retail
business estimated at approximately $1.3 million on a pre-tax basis at
December 31, 1998. In addition, Connecticut Valley also recorded
estimated total losses of $4.3 million pre-tax during the fourth quarter
of 1998 for disallowed power costs of $1.6 million and its refund
obligations of $2.7 million. Company management, however, continues to
believe that the NHPUC's actions are illegal and unconstitutional and
will present its arguments in the appropriate forum.

The NHPUC held a hearing on April 22, 1999 to determine whether to
modify Connecticut Valley's 1999 power rates by returning the rates to
the levels that were in effect on December 31, 1997. On May 17, 1999,
the NHPUC issued an order requiring Connecticut Valley to set temporary
rates at the level in effect as of December 31, 1997, subject to future
reconciliation, effective with bills issued on and after June 1, 1999.

The Court of Appeals issued a decision on January 24, 2000, which
upheld the Court's preliminary injunction enjoining the Commission's
restructuring plan. The decision also remanded the refund issue to the
Court stating:

"the district court may defer vacation of this injunction
against the refund order for up to 90 days. If within that
period it has decided the merits of the request for a
permanent injunction in a way inconsistent with refunds, or
has taken any other action that provides a showing that the
Company is likely to prevail on the merits in federal court
in barring the refunds, it may enter a superseding injunction
against the refund order, which the Commission may then
appeal to us. Otherwise, no later than the end of the 90-day
period, the district court must vacate its present injunction
insofar as it enjoins the Commission's refund order." The
parties have also submitted motions for summary judgment to
the Court, which the Court has under consideration.

On March 6, 2000 the Court issued a permanent injunction mandating
that the NHPUC allow Connecticut Valley to pass through to its retail
customers its wholesale costs incurred under the RS-2 rates schedule
with the Company. The Court also ruled that Connecticut Valley is
entitled to recover those wholesale costs that the NHPUC has disallowed
in retail rates since January 1, 1997.

This decision is subject to implementation by the NHPUC and is
subject to appeal.

On June 14, 1999, PSNH and various parties in New Hampshire
announced that a "Memorandum of Understanding" had been reached that is
intended to result in a detailed settlement proposal to the NHPUC that
would resolve PSNH's claims against the NHPUC's restructuring plan. On
July 6, 1999, PSNH petitioned the Court to stay its proceedings
indefinitely while the proposed settlement is reviewed and approved by
the NHPUC and the New Hampshire Legislature. On July 12, 1999, the
Company and Connecticut Valley objected to any stay that would allow the
NHPUC's rate freeze order to remain in effect for an extended period and
asked the Court to proceed with prompt hearings on its summary judgement
motion and trial on the merits. On October 20, 1999 the Court heard oral
arguments pertaining to the pretrial motions of the Company and the
NHPUC for summary judgement and dismissal, respectively. The Court took
the matters under advisement and indicated that a written order would
ensue.

FERC Proceedings

The Company filed an application with the FERC in June 1997, to
recover stranded costs in connection with its wholesale rate schedule
with Connecticut Valley and a notice of cancellation of the Connecticut
Valley rate schedule (contingent upon the recovery of the stranded costs
that would result from the cancellation of this rate schedule). In
December 1997, the FERC rejected the Company's proposal to recover
stranded costs through the imposition of a surcharge on our transmission
tariff, but indicated that it would consider an exit fee mechanism for
collecting stranded costs. The FERC denied the Company's motion for a
rehearing regarding the surcharge proposal, so the Company filed a
request with the FERC for an exit fee mechanism to collect the stranded
costs resulting from the cancellation of the contract with Connecticut
Valley. The stranded cost obligation sought to be recovered through an
exit fee, expressed on a net present value basis as of January 1, 2000,
is approximately $44.9 million. On September 14 and 15, 1998 the
Company participated in a settlement conference with an Administrative
Law Judge assigned for the settlement process at the FERC and the
parties to the Company's exit fee filing. During April and May 1999,
nine days of hearings were held at the FERC before an Administrative Law
Judge, who will determine, among other things, whether Connecticut
Valley qualifies for an exit fee, and if so, the amount of Connecticut
Valley's stranded cost obligation to be paid to the Company as an exit
fee. The ruling of the Administrative Law Judge is expected in the first
half of 2000, and the FERC will act on the judge's recommendations
sometime thereafter.

If the Company is unable to obtain an order authorizing the
recovery of costs in connection with the June 1997 FERC filing or in the
Federal Court, it is possible that the Company would be required to
recognize a pre-tax loss under this contract totaling approximately
$56.3 million on a pre-tax basis. The Company would also be required to
write-off approximately $3.0 million (pre-tax) in regulatory assets
associated with its wholesale business. However, even if the Company
obtains a FERC order authorizing the updated requested exit fee, if
Connecticut Valley is unable to recover its costs by increasing its
rates, Connecticut Valley would be required to recognize a loss under
this contract of approximately $44.9 million (pre-tax) representing
future under recovery of power costs.

Note 14
Commitments and contingencies

The Company's power supply is acquired from a number of sources
including its own generating units, jointly owned units, long-term
contracts and short-term purchases. The cost of power obtained from
sources other than wholly and jointly owned units, including payments
required to be made whether or not energy is received by the Company, is
reflected as Purchased power in the Consolidated Statement of Income.

Through its investments in four nuclear generating companies, three
of which (Maine Yankee, Connecticut Yankee and Yankee Atomic) are
permanently shut down, the Company is entitled to receive power from
those nuclear units. See Note 2 for a discussion of the Company's
obligations related to its investment in nuclear generating companies.
The Company is also a joint owner of the Unit #3 nuclear generating
plant.

Until its termination on April 30, 1998, the Company purchased
power and energy from Merrimack #2, pursuant to a contract dated July
16, 1966 entered into by and between VELCO and PSNH. Pursuant to the
contract, as amended, VELCO agreed to reimburse PSNH, in the proportion
which the VELCO quota bears to the demonstrated net capability of the
plant, for all fixed costs of the unit and operating costs of the unit
incurred by PSNH, which are reasonable and cost-effective for the
remaining term of the VELCO contract. In early 1998, PSNH took the
Merrimack Unit #2 facility off line, shut it down and commenced a
maintenance outage. In February, March and April of 1998, PSNH billed
VELCO for costs to complete the maintenance outage. VELCO disputes the
validity of a portion of the charges on grounds that the maintenance
performed at the unit was to extend the life of the Merrimack plant
beyond the term of the VELCO contract and that the charges in connection
with said investments were not reasonable and cost-effective for the
remaining term of the VELCO contract. The Company estimates the portion
of the disputed charges allocable to the Company could be as much as
$.5 million on a pre-tax basis.

The Company purchases power from a number of IPPs who own
qualifying facilities under the Public Utility Regulatory Policies Act
of 1978. These qualifying facilities produce energy using
hydroelectric, biomass, and refuse-burning generation. The majority of
these purchases are made from a state appointed purchasing agent who
purchases and redistributes the power to all Vermont utilities. Under
these long-term contracts, in 1999 the Company received 193,114 mWh of
which 139,407 mWh is associated with the Vermont Electric Power
Producers and 37,309 mWh with the New Hampshire/Vermont Solid Waste
Plant owned by Wheelabrator Claremont Company, L.P. The Company expects
to purchase approximately 205,821 mWh of small power output in each year
2000 through 2004. Based on the forecast level of production, the total
commitment in the next five years to purchase power from these
qualifying facilities is estimated to be $118.4 million.

The Company is purchasing varying amounts of power from
Hydro-Quebec under the VJO contract through 2016. Related contracts
were negotiated between the Company and Hydro-Quebec which in effect
alter the terms and conditions contained in the VJO contract, reducing
the overall power requirements and cost of the original contract.

The average annual amount of capacity that the Company will
purchase through October 31, 2016 is 132 mW. The total commitment to
purchase power under these contracts on a nominal basis is approximately
$975 million net of power sellbacks over the contract term. In February
1996, the Company reached an agreement with Hydro-Quebec which lowered
the 1997 cost of power by $5.8 million. As part of this agreement, the
Company delivers to NEPOOL under existing firm energy contracts or joint
marketing activities 54 mW of Phase II transmission capacity for a
five-year period which began July 1, 1996 through June 30, 2001.

In the early phase of the VJO contract, two sellback contracts were
negotiated, the first delaying the purchase of 25 mW of capacity and
associated energy, the second reducing the net purchase of Hydro-Quebec
power. In 1994, the Company negotiated a third sellback arrangement
whereby the Company receives an effective discount on up to 70 mW of
capacity starting in November 1995 for the 1996 contract year (declining
to 30 mW in the 1999 contract year). In exchange for this sellback,
Hydro-Quebec has the right to reduce capacity deliveries by up to 50 mW
beginning as early as 2004 until 2015, including the use of a like
amount of the Company's Phase I/II facility rights and the ability to
reduce the amounts of energy delivered for five years during a
fifteen-year term beginning in 2000.

There are specific contractual step up provisions that provide that
in the event any VJO member fails to meet its obligation under the
contract with Hydro-Quebec, the balance of the VJO participants,
including the Company, will "step up" to the defaulting party's share on
a pro-rata basis. As of December 31, 1999 the Company's VJO obligation
is approximately 43% or $975 million on a nominal basis over the term of
the contract ending in 2016. The total VJO contract obligation on a
nominal basis over the term of the contract is approximately $2.1
billion.

During January 1998, a significant ice storm affected parts of New
York, New England and the Province of Quebec, Canada. This storm
damaged major components of the Hydro-Quebec transmission system over
which power is supplied to Vermont under the VJO Power Contract with
Hydro-Quebec. This resulted in a 61-day interruption of a significant
portion of scheduled contractual energy deliveries into Vermont. The
ice storm's effect on Hydro-Quebec's transmission system caused the VJO
to examine Hydro-Quebec's overall reliability and ability to deliver
energy. On the basis of that examination, the VJO determined that
Hydro-Quebec has been and remains unable to make available capacity with
the degree of firmness required by the VJO Power Contract. That
determination has prompted the VJO to initiate an arbitration
proceeding. In the arbitration, the VJO is seeking to terminate the
contract, to recover damages associated with Hydro-Quebec's failure to
comply with the contract, and to recover capacity payments made during
the period of non-delivery.

In September 1999 an initial two weeks of hearings were held
dealing primarily with issues of contract interpretation. Additional
hearings dealing with technical issues will be held in the second and
third quarters of 2000. The Company expects a decision by the end of
2000. In accordance with a PSB Accounting Order, the Company has
deferred incremental costs associated with this arbitration of
approximately $2.0 million. Recovery of these costs will be determined
in the next rate proceedings.

Joint-ownership - The Company's ownership interests in jointly owned
generating and transmission facilities are set forth in the table that
follows and recorded in the Company's Consolidated Balance Sheet
(dollars in thousands):

Fuel In Service MW December 31
Type Ownership Date Entitlement 1999 1998
<S> <C> <C> <C> <C> <C> <C>
Generating plants:
Wyman #4 Oil 1.78% 1978 11 $ 3,347 $ 3,347
Joseph C. McNeil Various 20.00% 1984 11 15,240 15,093
Millstone Unit #3 Nuclear 1.73% 1986 20 75,561 75,444
Highgate transmission
facility 47.35% 1985 14,042 13,930
-------- --------
108,190 107,814
Accumulated depreciation 41,201 37,934
-------- --------
$ 66,989 $ 69,880
======= =======
</TABLE>

The Company's share of operating expenses for these facilities is
included in the corresponding operating accounts on the Consolidated
Statement of Income. Each participant in these facilities must provide
for its own financing.

VELCO is currently in the process of upgrading its transmission
facilities in the Burlington, Vermont area where the Joseph C. McNeil
generating plant is located. These transmission improvements will
reduce the current need for the Joseph C. McNeil generating plant to run
in support of area reliability and are expected to be in place in the
second half of 2001. The Company anticipates that upon completion of
the upgrade, the Joseph C. McNeil generating plant may not operate at
its current capacity factor.

Environmental - The Company is engaged in various operations and
activities which subject it to inspection and supervision by both
federal and state regulatory authorities including the United States
Environmental Protection Agency ("EPA"). It is Company policy to comply
with all environmental laws. The Company has implemented various
procedures and internal controls to assess and assure compliance. If
non-compliance is discovered, corrective action is taken. Based on
these efforts and the oversight of those regulatory agencies having
jurisdiction, the Company believes it is in compliance, in all material
respects, with all pertinent environmental laws and regulations.

Company operations occasionally result in unavoidable, inadvertent
releases of regulated substances or materials, for example the rupture
of a pole mounted transformer, or a broken hydraulic line. Whenever the
Company learns of such a release, the Company responds in a timely
fashion and in a manner that complies with all federal and state
requirements. Except as discussed in the following paragraphs, the
Company is not aware of any instances where it has caused, permitted or
suffered a release or spill on or about its properties or otherwise
which is likely to result in any material environmental liabilities to
the Company.

The Company is an amalgamation of more than 100 predecessor
companies. Those companies engaged in various operations and activities
prior to being merged into the Company. At least two of these companies
were involved in the production of gas from coal to sell and distribute
to retail customers at three different locations. These activities were
discontinued by the Company in the late 1940's or early 1950's. The
coal gas manufacturers, other predecessor companies, and the Company
itself may have engaged in waste disposal activities which, while legal
and consistent with commercially accepted practices at the time, may not
meet modern standards and thus represent potential liability.

The Company continues to investigate, evaluate, monitor and, where
appropriate, remediate contaminated sites related to these historic
activities. The Company's policy is to accrue a liability for those
sites where costs for remediation, monitoring and other future
activities are probable and can be reasonably estimated. As part of
that process, the Company also researches the possibility of insurance
coverage that could defray any such remediation expenses.

Cleveland Avenue Property - The Company's Cleveland Avenue property
located in the City of Rutland, Vermont, a site where one of its
predecessors operated a coal-gasification facility and later the Company
sited various operations functions. Due to the presence of coal tar
deposits and Polychlorinated Biphenyl ("PCB") contamination and
uncertainties as to potential off-site migration of those contaminants,
the Company conducted studies in the late 1980's and early 1990's to
determine the magnitude and extent of the contamination. After
completing its preliminary investigation, the Company engaged a
consultant to assist in evaluating clean-up methodologies and provide
cost estimates. Those studies indicated the cost to remediate the site
would be approximately $5.0 million. This was charged to expense in the
fourth quarter of 1992. Site investigation has continued over the last
several years and the Company continues to work with the State in a
joint effort to develop a mutually acceptable solution.

Brattleboro Manufactured Gas Facility - From the early to late
1940's, the Company owned and operated a manufactured gas facility in
Brattleboro, Vermont. The Company recently received a letter from the
State of New Hampshire asking the Company to conduct a scoping study in
and around the site of the former facility. The Company has engaged a
qualified consultant to do the scoping study and a search for other
Potential Responsible Parties. At this time the Company has not
finalized an estimate of its potential liability at this site.

Dover, New Hampshire Manufactured Gas Facility - The Company was
recently contacted by PSNH with respect to this site. PSNH alleges the
Company is partially liable for remediation of this site. PSNH's
allegation is premised on the fact that prior to PSNH's purchase of the
facility, it was operated by Twin State Gas and Electric ("Twin State").
Twin State merged with the Company on the same day the facility was sold
to PSNH. The Company is researching the underlying transactions in an
effort to determine the nature and extent of any liability it may have.
At this time the Company has not finalized an estimate of its potential
liability at this site.

The Company is not subject to any pending or threatened litigation
with respect to any other sites that have the potential for causing the
Company to incur material remediation expenses, nor has the EPA or other
federal or state agency sought contribution from the Company for the
study or remediation of any such sites.

As of December 31, 1999, a reserve of $9.9 million has been
established representing management's best estimate of the costs to
remediate the sites.

Dividend restrictions - The indentures relating to long-term debt,
the Articles of Association and a covenant contained in the
Reimbursement Agreements to the letters of credit, supporting the
Company's tax exempt revenue bonds, contain certain restrictions on the
payment of cash dividends on capital stock. Under the most restrictive
of such provisions, approximately $29.4 million of retained earnings was
not subject to dividend restriction at December 31, 1999.

Under the Company's Second Mortgage Indenture, certain additional
restrictions on the payment of dividends would become effective if the
Company's Second Mortgage Bonds are rated below investment grade. Under
the most restrictive of these provisions, approximately $16.6 million of
retained earnings would not be subject to dividend restrictions at
December 31, 1999.

In addition, Catamount and SmartEnergy Water Heating Services,
Inc., have debt instruments in place that restrict the amount of
dividends on capital stock that they are able to pay.

Leases and support agreements - The Company participated with other
electric utilities in the construction of the Phase I Hydro-Quebec
transmission facilities in northeastern Vermont, which were completed at
a total cost of approximately $140 million. Under a support agreement
relating to the Company's participation in the facilities, the Company
is obligated to pay its 4.42% share of Phase I Hydro-Quebec capital
costs over a 20-year recovery period through and including 2006. The
Company also participated in the construction of Phase II Hydro-Quebec
transmission facilities constructed throughout New England, which were
completed at a total cost of approximately $487 million. Under a
similar support agreement, the Company is obligated to pay its 5.132%
share of Phase II Hydro-Quebec capital costs over a 25-year recovery
period through and including 2015. All costs under these support
agreements are recorded as purchased transmission expense in accordance
with the Company's rate-making policies. Future minimum payments will be
approximately $3.0 million for each year from 2000 through 2015 and will
decline thereafter. The Company's shares of the net capital cost of
these facilities, totaling approximately $16.2 million, are classified
in the accompanying Consolidated Balance Sheet as "Utility Plant" and
"Capital lease obligations" (current and non-current).

Minimum rental commitments of the Company under non-cancelable
leases as of December 31, 1999, are considered minimal as the majority
of the Company's leases are cancelable after one year from lease
inception. Total rental expense entering into the determination of net
income, consisting principally of vehicle and equipment rentals, was
approximately $3.8 million for 1997, $4.0 million for 1998 and
$4.2 million for 1999.

Legal proceedings - On August 7, 1997, the Company and eight other
non-operating owners of Unit #3 filed a demand for arbitration with
Connecticut Light and Power Company and Western Massachusetts Electric
Company, both NU affiliates, and lawsuits against NU and its trustees.
The arbitration and lawsuits seek to recover costs associated with
replacement power, operation and maintenance costs and other costs
resulting from the shutdown of Unit #3. The non-operating owners claim
that NU and two of its wholly owned subsidiaries failed to comply with
NRC's regulations, failed to operate the facility in accordance with
good operating practice and attempted to conceal their activities from
the non-operating owners and the NRC. A mediator has been hired in an
attempt to settle prior arbitration and the lawsuit.

On September 15, 1999, NU announced that it intends to auction its
nuclear generating plants, including Unit #3. We cannot predict at this
time the effect of such an auction, if it occurs, on the Company or on
the ongoing litigation.

On October 27, 1999, NU and NEP, disclosed that NU had reached an
agreement with NEP and MEC, two of the non-operating minority joint
owners, to settle their claims in the arbitration and lawsuits. The
settlement involves payment of fixed and contingent amounts to NEP and
MEC and the inclusion of their Unit #3 interests in NU's auction of the
plant. In addition, on January 28, 2000 CMP, also one of the
non-operating minority joint owners, disclosed that NU and CMP had
reached an agreement to settle CMP's claims in the arbitration and
litigation on terms similar to the NEP and MEC settlement. The other
non-operating minority joint owners, including the Company, remain
active in the arbitration and lawsuits and in seeking to settle our
claims against NU.

In addition to the proceedings described herein, the Company is
involved in litigation in the normal course of business which the
Company does not believe will have a material adverse effect on the
financial position or results of operations.

Change of control - The Company has management continuity
agreements with certain Officers which become operative upon a change in
control of the Company and continue in effect until January 1, 2003.
Potential severance expense under the agreements varies over time
depending on officers' compensation and age at the time of the change of
control.

Note 15
Recent Accounting Pronouncements

In June 1997, the FASB issued SFAS No. 130, Reporting Comprehensive
Income, effective for fiscal years beginning after December 15, 1997.
SFAS No. 130 established standards for reporting and display of
comprehensive income and its components in a full set of general-purpose
financial statements. It requires that an enterprise classify items of
other comprehensive income by their nature in a financial statement and
display the accumulated balance of other comprehensive income separately
in the equity section of a statement of financial position. In 1999 and
1998 the Company recognized pre-tax minimum pension liability
adjustments of $0.4 million and $0.6 million, respectively, or
$0.1 million and $0.4 million net of tax, respectively.

Effective January 1, 1999, the Company adopted Emerging Issues Task
Force Issue ("EITF") No. 98-10, Accounting for Contracts Involved in
Energy Trading and Risk Management Activities. EITF Issue 98-10
requires energy trading contracts to be recorded at fair value on the
balance sheet, with the changes in fair value included in earnings. In
1999, the Company recognized a net gain of $.2 million in the
accompanying Consolidated Statement of Income for its open electricity
purchase and sale commitments. As discussed in Note 1, the Company
decided to terminate its trading alliance with Virginia Power during the
third quarter of 1999 and the Company does not intend to continue its
trading operations following the maturity of its remaining open
contracts in 2000.

Note 16
Segment Reporting

In 1998 the Company adopted SFAS No.131,"Disclosures about Segments
of an Enterprise and Related Information," which establishes standards
for reporting operating segments and related disclosures. It also
establishes standards for related disclosures. Operating segments are
defined as components of an enterprise about which separate financial
information is available that is evaluated regularly by the chief
operating decision maker, or decision making group, in deciding how to
allocate resources and in assessing performance. The Company's chief
operating decision making group is the Board of Directors, which is
comprised of nine Directors including the Chairman of the Board and the
Company's President and Chief Executive Officer. The operating segments
are managed separately because each operating segment represents a
different retail rate jurisdiction or offers different products or
services.

The Company's reportable operating segments include Central Vermont
Public Service Corporation ("CV") which engages in the purchase,
production, transmission, distribution and sale of electricity in
Vermont; Connecticut Valley Electric Company Inc. ("CVEC") which
distributes and sells electricity in parts of New Hampshire; Catamount
which invests in non-regulated, energy-supply projects and SmartEnergy
which pursues retail alliances to market energy and related products and
services, engages in the sale of or rental of electric water heaters and
has a 70% ownership interest in HSS. CVEC, while managed on an
integrated basis with CV, is presented separately because of its
separate and distinct regulatory jurisdiction. Other operating segments
include a segment below the quantitative threshold for separate
disclosure. This operating segment is C. V. Realty, Inc., a real estate
company whose purpose is to own, acquire, buy, sell and lease real and
personal property and interests therein related to the utility business.
Segment information for 1998 and 1997 has been restated to separately
present SmartEnergy which became a reportable segment in 1999.

The accounting policies of the operating segments are the same as
those described in the summary of significant accounting policies.
Intersegment revenues include sales of purchased power to CVEC and
revenues for support services to CVEC, Catamount and SmartEnergy.

These intersegment sales and services for each jurisdiction are
based on actual rates or current costs. The Company evaluates
performance based on stand alone operating segment net income.

<PAGE>
Financial Information by industry segment for the three years ended
December 31, 1999, is as follows (dollars in thousands):

<TABLE>
<CAPTION>
Reclassification
CV CVEC and Consolidating
1999 VT NH Catamount SmartEnergy Other(1) Entries Consolidated
---- -------- -------- --------- ----------- ------- ---------------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Revenues from external
customers $399,268 $20,551 $ 1,316 $ 7,306 7 $ 8,633 $419,815
Intersegment revenues 11,938 - - - - 11,938 -
Depreciation & other(2) 12,221 463 38 347 3 388 12,684
Reversal of estimated loss
on power contracts(3) - 1,586 - - - - 1,586
Estimated loss on power
contracts(3) - (1,202) - - - - (1,202)
Purchased power disallowance(3) (2,859) (2,859)
Reversal of purchased
power disallowance(3) 7,361 - - - - - 7,361
Taxes on income 10,408 49 1,382 (1,960) 24 (457) 10,360
Operating income (loss) 24,146 491 (2,871) 2,453 (23) (455) 24,651
Equity income-affiliates(4) 2,844 - - - - - 2,844
Other income (expenses), net 2,145 5 563 (22) 69 1,513 1,247
Interest expense, net 11,880 393 101 39 - 255 12,158
Net income (loss) 18,067 102 2,061 (2,873) (773) - 16,584
Investments in affiliates,
at equity 25,501 - - - - 25,501
Total assets 504,120 12,670 46,798 4,526 36,973 41,128 563,959
Capital expenditures 12,723 393 115 - - 13,231
1998
----
Revenues from external
customers $284,907 $18,933 $ 412 $ 7,184 $ - $ 7,601 $303,835
Intersegment revenues 12,755 - - - - 12,755 -
Depreciation & other(2) 19,811 442 41 354 3 398 20,253
Reversal of estimated loss
on power contracts(3) - 5,500 - - - - 5,500
Estimated loss on power
contracts(3) - (1,586) - - - - (1,586)
Purchased power disallowance(3) (7,361) - - - - - (7,361)
Taxes on income (682) 399 1,914 (1,079) (3) 832 (283)
Operating income (loss) 7,015 1,107 (3,689) (1,623) (20) (5,201) 7,991
Equity income-affiliates(4) 3,191 - - - - - 3,191
Other income (expenses), net 1,343 22 490 78 17 (1,511) 3,461
Interest expense, net 10,024 387 276 1 - 28 10,660
Net income (loss) 1,525 742 3,265 (1,546) (3) - 3,983
Investments in affiliates,
at equity 26,142 - - - - - 26,142
Total assets 473,879 11,803 45,616 4,360 37,728 43,104 530,282
Capital expenditures 15,497 549 - - - - 16,046
1997
----
Revenues from external
customers $285,102 $19,635 $ 348 $ 1,802 $ - $ 2,155 $304,732
Intersegment revenues 10,818 - - - - 10,818 -
Depreciation & other(2) 26,733 442 49 355 3 407 27,175
Estimated loss on power
contracts(3) - (5,500) - - - - (5,500)
Extraordinary charge,
net of taxes - 811 - - - - 811
Sale of Non-Utility Assets 2,118 - 2,891 - - - 5,009
Taxes on income 9,177 (1,605) 2,097 (500) (37) 1,559 7,573
Operation income (loss) 21,364 (2,597) (4,701) (761) (60) (5,391) 18,636
Equity income-affiliates(4) 3,214 - - - - - 3,214
Other income (expenses), net 1,561 8 3,453 22 13 50 5,007
Interest expense, net 9,259 409 76 - - 38 9,706
Net income (loss) 16,880 (3,807) 4,054 (739) (48) - 16,340
Investments in affiliates,
at equity 26,495 - - - - - 26,495
Total assets 481,971 11,648 41,215 2,611 356 5,861 531,940
Capital expenditures 13,220 621 - - - - 13,841

(1) Includes a segment below the quantitative threshold.
(2) Includes net deferral and amortization of nuclear replacement
energy and maintenance costs (included in Purchased power)
and amortization of conservation and load management costs
(included in Other operation expenses) in the accompanying
Consolidated Statement of Income.
(3) Included in Purchased power in the accompanying Consolidated
Statement of Income.
(4) See Note 2 herein for CV's investments in affiliates.
</TABLE>

Note 17
Unaudited Quarterly Financial Information

The following quarterly financial information is unaudited and
includes all adjustments consisting of normal recurring accruals which
are, in the opinion of management, necessary for a fair statement of
results of operations for such periods. Variations between quarters
reflect the seasonal nature of the Company's business (dollars in
thousands, except per share amounts):

<TABLE>
<CAPTION>
Quarter Ended 12 Months
March June September December Ended

<S> <C> <C> <C> <C> <C>
1999
Operating revenues $98,642 $93,139 $113,221 $114,813 $419,815
Operating income $13,855 $ 1,863 $ 1,758 $ 7,175 $ 24,651
Net income $12,730 $ 416 $ 410 $ 3,028 $ 16,584
Earnings per share
of common stock $1.07 $.00 $.00 $.22 $1.28

1998
Operating revenues $83,958 $66,406 $69,522 $ 83,949 $303,835
Operating income (loss) $10,679 $(4,079) $ 931 $ 460 $ 7,991
Net income (loss) $10,264 $(5,452) $ (229) $ (600) $ 3,983
Earnings (losses) per
share of common stock $ .86 $ (.52) $(.06) $(.10) $ .18

</TABLE>

Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.

None.

PART III

Item 10. Directors and Executive Officers of the Registrant.

The information required by this item with respect to the Company's
directors is incorporated herein by this reference to "Election of
Directors" and Section 16(a) Beneficial Ownership Reporting Compliance
in the Proxy Statement for the 2000 Annual Meeting of Stockholders. The
Executive Officers information is listed under Part I, Item 1.
Definitive proxy materials will be filed with the Securities and
Exchange Commission pursuant to Regulation 14A on or about March 28,
2000.

Item 11. Executive Compensation.

The information required by this item concerning executive
compensation and directors' compensation is set forth in the sections
entitled "Executive Compensation and Other Transactions", "Directors'
Compensation", "Report of the Compensation Committee on Executive
Compensation" and "Five-Year Shareholder Return Comparison Performance
Graph" in the Proxy Statement of the Company for the 2000 Annual Meeting
of Stockholders, which are being incorporated herein by reference.
Definitive proxy materials will be filed with the Securities and
Exchange Commission pursuant to Regulation 14A on or about March 28,
2000.

Item 12. Security Ownership of Certain Beneficial Owners and
Management.

The information required by this item concerning security ownership
is set forth in the section entitled "Stock Ownership of Directors,
Nominees, Executive Officers and Certain Beneficial Owners" in the Proxy
Statement for the 2000 Annual Meeting of Stockholders, which is being
incorporated herein by reference. Definitive proxy materials will be
filed with the Securities and Exchange Commission pursuant to Regulation
14A on or about March 28, 2000.

Item 13. Certain Relationships and Related Transactions.

None

Filed
Herewith
at Page
PART IV

Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K.

(a)1. The following financial statements for Central
Vermont Public Service Corporation and its
wholly owned subsidiaries are filed as part
of this report: (See Item 8)

1.1 Consolidated Statement of Income, for
each of the three years ended
December 31, 1999

Consolidated Statement of Cash Flows,
for each of the three years ended
December 31, 1999

Consolidated Balance Sheet at December 31,
1999 and 1998

Consolidated Statement of Capitalization
at December 31, 1999 and 1998

Consolidated Statement of Changes in
Common Stock Equity for each of the
three years ended December 31, 1999

Notes to Consolidated Financial Statements

(a)2. Financial Statement Schedules:

2.1 Central Vermont Public Service Corporation and
its wholly owned subsidiaries:

Schedule II - Reserves for each of the
three years ended December 31, 1999

Schedules not included have been omitted because they
are not applicable or the required information is shown
in the financial statements or notes thereto. Separate
financial statements of the Registrant (which is primarily
an operating company) have been omitted since they are
consolidated only with those of totally held subsidiaries.
Separate financial statements of subsidiary companies not
consolidated have been omitted since, if considered in
the aggregate, they would not constitute a significant
subsidiary. Separate financial statements of 50% or less
owned persons for which the investment is accounted for
by the equity method by the Registrant have been omitted
since, if considered in the aggregate, they would not
constitute a significant investment.

(a)3. Exhibits (* denotes filed herewith)

Each document described below is incorporated by reference
to the appropriate exhibit numbers and the Commission file
numbers indicated in parentheses, unless the reference to
the document is marked as follows:

* - Filed herewith.

Copies of any of the exhibits filed with the Securities and
Exchange Commission in connection with this document may be
obtained from the Company upon written request.
<PAGE>
Exhibit 3 Articles of Incorporation and By-Laws

3-1 By-Laws, as amended June 2, 1997. (Exhibit 3-1, Form 10-Q
June 30, 1997, File No. 1-8222)

3-2 Articles of Association, as amended August 11, 1992.
(Exhibit No. 3-2, 1992 10-K, File No. 1-8222)

Exhibit 4 Instruments defining the rights of security holders,
including Indentures

Incorporated herein by reference:

4-1 Mortgage dated October 1, 1929, between the Company and Old
Colony Trust Company, Trustee, securing the Company's First
Mortgage Bonds. (Exhibit B-3, File No. 2-2364)

4-2 Supplemental Indenture dated as of August 1, 1936.
(Exhibit B-4, File No. 2-2364)

4-3 Supplemental Indenture dated as of November 15, 1943.
(Exhibit B-3, File No. 2-5250)

4-4 Supplemental Indenture dated as of December 1, 1943.
(Exhibit No. B-4, File No. 2-5250)

4-5 Directors' resolutions adopted December 14, 1943,
establishing the Series C Bonds and dealing with other
related matters. (Exhibit B-5, File No. 2-5250)

4-6 Supplemental Indenture dated as of April 1, 1944.
(Exhibit No. B-6, File No. 2-5466)

4-7 Supplemental Indenture dated as of February 1, 1945.
(Exhibit 7.6, File No. 2-5615) (22-385)

4-8 Directors' resolutions adopted April 9, 1945, establishing
the Series D Bonds and dealing with other matters.
(Exhibit 7.8, File No. 2-5615 (22-385)

4-9 Supplemental Indenture dated as of September 2, 1947.
(Exhibit 7.9, File No. 2-7489)

4-10 Supplemental Indenture dated as of July 15, 1948, and
directors' resolutions establishing the Series E Bonds and
dealing with other matters. (Exhibit 7.10, File No. 2-8388)

4-11 Supplemental Indenture dated as of May 1, 1950, and
directors' resolutions establishing the Series F Bonds and
dealing with other matters. (Exhibit 7.11, File No. 2-8388)

4-12 Supplemental Indenture dated August 1, 1951, and directors'
resolutions, establishing the Series G Bonds and dealing with
other matters. (Exhibit 7.12, File No. 2-9073)

4-13 Supplemental Indenture dated May 1, 1952, and directors'
resolutions, establishing the Series H Bonds and dealing with
other matters. (Exhibit 4.3.13, File No. 2-9613)

4-14 Supplemental Indenture dated as of July 10, 1953.
(July, 1953 Form 8-K, File No. 1-8222)

4-15 Supplemental Indenture dated as of June 1, 1954, and
directors' resolutions establishing the Series K Bonds and
dealing with other matters.
(Exhibit 4.2.16, File No. 2-10959)

4-16 Supplemental Indenture dated as of February 1, 1957, and
directors' resolutions establishing the Series L Bonds and
dealing with other matters.
(Exhibit 4.2.16, File No. 2-13321)

4-17 Supplemental Indenture dated as of March 15, 1960.
(March, 1960 Form 8-K, File No. 1-8222)

4-18 Supplemental Indenture dated as of March 1, 1962.
(March, 1962 Form 8-K, File No. 1-8222)

4-19 Supplemental Indenture dated as of March 2, 1964.
(March, 1964 Form 8-K, File No, 1-8222)

4-20 Supplemental Indenture dated as of March 1, 1965,
and directors' resolutions establishing the Series M Bonds
and dealing with other matters. (April, 1965 Form 8-K, File
No. 1-8222)

4-21 Supplemental Indenture dated as of December 1, 1966, and
directors' resolutions establishing the Series N Bonds and
dealing with other matters. (January, 1967 Form 8-K,
File No. 1-8222)

4-22 Supplemental Indenture dated as of December 1, 1967, and
directors' resolutions establishing the Series O Bonds and
dealing with other matters. (December, 1967 Form 8-K,
File No. 1-8222)

4-23 Supplemental Indenture dated as of July 1, 1969, and
directors' resolutions establishing the Series P Bonds and
dealing with other matters. (Exhibit B.23, July, 1969
Form 8-K, File No. 1-8222)

4-24 Supplemental Indenture dated as of December 1, 1969, and
directors' resolutions establishing the Series Q Bonds
January, and dealing with other matters.
(Exhibit B.24, January, 1970 Form 8-K, File No. 1-8222)

4-25 Supplemental Indenture dated as of May 15, 1971, and
directors' resolutions establishing the Series R Bonds and
dealing with other matters. (Exhibit B.25, May, 1971,
Form 8-K, File No. 1-8222)

4-26 Supplemental Indenture dated as of April 15, 1973, and
directors' resolutions establishing the Series S Bonds and
dealing with other matters. (Exhibit B.26, May, 1973,
Form 8-K, File No. 1-8222)

4-27 Supplemental Indenture dated as of April 1, 1975, and
directors' resolutions establishing the Series T Bonds and
dealing with other matters. (Exhibit B.27, April, 1975,
Form 8-K, File No. 1-8222)

4-28 Supplemental Indenture dated as of April 1, 1977.
(Exhibit 2.42, File No. 2-58621)

4-29 Supplemental Indenture dated as of July 29, 1977, and
directors' resolutions establishing the Series U, V, W,
and X Bonds and dealing with other matters. (Exhibit 2.43,
File No. 2-58621)

4-30 Thirtieth Supplemental Indenture dated as of
September 15, 1978, and directors' resolutions establishing
the Series Y Bonds and dealing with other matters.
(Exhibit B-30, 1980 Form 10-K, File
No. 1-8222)

4-31 Thirty-first Supplemental Indenture dated as of
September 1, 1979, and directors' resolutions establishing
the Series Z Bonds and dealing with other matters.
(Exhibit B-31, 1980 Form 10-K, File No. 1-8222)

4-32 Thirty-second Supplemental Indenture dated as of
June 1, 1981, and directors' resolutions establishing the
Series AA Bonds and dealing with other matters.
(Exhibit B-32, 1981 Form 10-K, File No. 1-8222)

4-45 Thirty-third Supplemental Indenture dated as of
August 15, 1983, and directors' resolutions establishing the
Series BB Bonds and dealing with other matters.
(Exhibit B-45, 1983 Form 10-K, File No. 1-8222)

4-46 Bond Purchase Agreement between Merrill, Lynch, Pierce,
Fenner & Smith, Inc., Underwriters and The Industrial
Development Authority of the State of New Hampshire, issuer
and Central Vermont Public Service Corporation.
(Exhibit B-46, 1984 Form 10-K, File No. 1-8222)

4-47 Thirty-Fourth Supplemental Indenture dated as of
January 15, 1985, and directors' resolutions establishing the
Series CC Bonds and Series DD Bonds and matters connected
therewith. (Exhibit B-47, 1985 Form 10-K, File No. 1-8222)

4-48 Bond Purchase Agreement among Connecticut Development
Authority and Central Vermont Public Service Corporation with
E. F. Hutton & Company Inc. dated December 11, 1985.
(Exhibit B-48, 1985 Form 10-K, File No. 1-8222)

4-49 Stock-Purchase Agreement between Vermont Electric Power
Company, Inc. and the Company dated August 11, 1986 relative
to purchase of Class C Preferred Stock. (Exhibit B-49, 1986
Form 10-K, File No. 1-8222)

4-50 Thirty-Fifth Supplemental Indenture dated as of
December 15, 1989 and directors' resolutions establishing the
Series EE, Series FF and Series GG Bonds and matters
connected therewith. (Exhibit 4-50, 1989 Form 10-K,
File No. 1-8222)

4-51 Thirty-Sixth Supplemental Indenture dated as of
December 10, 1990 and directors' resolutions establishing the
Series HH Bonds and matters connected therewith.
(Exhibit 4-51, 1990 Form 10-K, File No. 1-8222)

4-52 Thirty-Seventh Supplemental Indenture dated
December 10, 1991 and directors' resolutions establishing the
Series JJ Bonds and matters connected therewith.
(Exhibit 4-52, 1991 Form 10-K, File No. 1-8222)

4-53 Thirty-Eight Supplemental Indenture dated December 10, 1993
establishing Series KK, LL, MM, NN, OO. (Exhibit 4-53, 1993
Form 10-K, File No. 1-8222)

4-54 Thirty-Ninth Supplemental Indenture Dated December 29, 1997.
(Exhibit 4-54, 1997 Form 10-K, File No. 1-8222)

4-55 Fortieth Supplemental Indenture Dated January 28, 1998.
(Exhibit 4-55, 1997 Form 10-K, File No. 1-8222)

4-56 Credit Agreement Dated As of November 5, 1997 among
Central Vermont Public Service Corporation, The Lenders
Named Herein and Toronto-Dominion (Texas), Inc., as Agent.
(Exhibit 10.83, 1997 Form 10-K, File No. 1-8222)

4-56.1 First Amendment to Credit Agreement Dated as of
April 15, 1998 (Exhibit 10.83.1, Form 10-Q,
June 30, 1998, File No. 1-8222)

4-56.2 Second Amendment to Credit Agreement Dated as of
June 2, 1998 (Exhibit 10.83.2, 1997 Form 10-Q,
June 30, 1998, File No. 1-8222)

4-56.3 Third Amendment to Credit Agreement Dated as of
October 5, 1998 (Exhibit 4-56.3, 1998 Form 10-K,
File No. 1-8222)

4-56.4 Open-End Mortgage, Security Agreement, Assignment of
Rents and Leases, Fixture Filing, and Financing
Statement Dated as of October 5, 1998 between the
Company, as Mortgagor, in Favor of Toronto Dominion
(Texas), Inc. as Collateral Agent for the Secured
Parties (Exhibit 4-56.4, 1998 Form 10-K, File No.
1-8222)

Fourth Amendment to Credit Agreement, dated as of
May 25, 1999 (Exhibit 4-56.4, Form 10-Q,
June 30, 1999, File No. 1-8222)

4-56.5 Security Agreement, dated as of October 5, 1998,
between the Company and Toronto Dominion (Texas),
Inc. (Exhibit 4-56.5, 1998 Form 10-K, File No.
1-8222)

4-57 Forty-First Supplemental Indenture, dated as of July 19, 1999
and resolutions establishing Series PP (Millstone) Bonds,
Series QQ (Seabrook) Bonds and Series RR (East Barnet) Bonds
And matters connected therewith adopted July 19, 1999
(Exhibit 4-57, Form 10-Q, September 30, 1999, File No.
1-8222)

4-58 Second Mortgage Indenture, dated as of July 15, 1999, Central
Vermont Public Service Corporation to the Bank of New York,
Trustee (Exhibit 4-58, Form 10-Q, September 30, 1999,
File No. 1-8222)

4-59 First Supplemental Indenture to the Second Mortgage, Central
Vermont Public Service Corporation to the Bank of New York,
Trustee, dated as of July 15, 1999, creating an issue of
Mortgage Bonds, 8-1/8% Second Mortgage Bonds due 2004
(Exhibit 4-59, Form 10-Q, September 30, 1999, File No.
1-8222)

4-60 A/B Exchange Registration Rights Agreement, dated as of
July 30, 1999 by and among Central Vermont Public Service
Corporation and Donaldson, Lufkin & Jenrette Securities
Corporation, TD Securities (USA) Inc. (Exhibit 4-60, Form
10-Q, September 30, 1999, File No. 1-8222)

Exhibit 10 Material Contracts (*Denotes filed herewith)

Incorporated herein by reference:

10.l Copy of firm power Contract dated August 29, 1958, and
supplements thereto dated September 19, 1958,
October 7, 1958, and October 1, 1960, between the Company
and the State of Vermont (the "State"). (Exhibit C-1,
File No. 2-17184)

10.1.1 Agreement setting out Supplemental NEPOOL
Understandings dated as of April 2, 1973.
(Exhibit C-22, File No. 5-50198)

10.2 Copy of Transmission Contract dated June 13, 1957, between
Velco and the State, relating to transmission of power.
(Exhibit 10.2, 1993 Form 10-K, File No. 1-8222)
10.2.1 Copy of letter agreement dated August 4, 1961,
between Velco and the State. (Exhibit C-3, File No. 2-26485)

10.2.2 Amendment dated September 23, 1969. (Exhibit C-4,
File No. 2-38161)

10.2.3 Amendment dated March 12, 1980. (Exhibit C-92,
1982 Form 10-K, File No. 1-8222)

10.2.4 Amendment dated September 24, 1980. (Exhibit C-93,
1982 Form 10-K, File No. 1-8222)

10.3 Copy of subtransmission contract dated August 29, 1958,
between Velco and the Company (there are seven similar
contracts between Velco and other utilities). (Exhibit 10.3,
1993 Form 10-K, Form No. 1-8222)

10.3.1 Copies of Amendments dated September 7, 196l,
November 2, 1967, March 22, 1968, and
October 29, 1968. (Exhibit C-6, File No. 2-32917)

10.3.2 Amendment dated December 1, 1972. (Exhibit 10.3.2,
1993 Form 10-K, File No. 1-8222)

10.4 Copy of Three-Party Agreement dated September 25, 1957,
between the Company, Green Mountain and Velco. (Exhibit C-7,
File No. 2-17184)

10.4.1 Superseding Three Party Power Agreement dated
January 1, 1990. (Exhibit 10-201, 1990 Form 10-K,
File No. 1-8222)

10.4.2 Agreement Amending Superseding Three Party Power
Agreement dated May 1, 1991. (Exhibit 10.4.2, 1991
Form 10-K, File No. 1-8222)

10.5 Copy of firm power Contract dated December 29, 1961, between
the Company and the State, relating to purchase of Niagara
Project power. (Exhibit C-8, File No. 2-26485)

10.5.1 Amendment effective as of January 1, 1980. (Exhibit
10.5.1, 1993 Form 10-K, File No. 1-8222)

10.6 Copy of agreement dated July 16, 1966, and letter supplement
dated July 16, 1966, between Velco and Public Service Company
of New Hampshire relating to purchase of single unit power
from Merrimack II. (Exhibit C-9, File No. 2-26485)

10.6.1 Copy of Letter Agreement dated July 10, 1968,
modifying Exhibit A. (Exhibit C-10, File No.
2-32917)

10.7 Copy of Capital Funds Agreement between the Company and
Vermont Yankee dated as of February 1, 1968. (Exhibit C-11,
File No. 70-4611)

10.7.1 Copy of Amendment dated March 12, 1968. (Exhibit
C-12, File No. 70-4611)

10.7.2 Copy of Amendment dated September 1, 1993. (Exhibit
10.7.2, 1994 Form 10-K, File No. 1-8222)

10.8 Copy of Power Contract between the Company and Vermont Yankee
dated as of February 1, 1968. (Exhibit C-13, File No.
70-4591)

10.8.1 Amendment dated April 15, 1983. (10.8.1, 1993 Form
10-K, File No. 1-8222)

10.8.2 Copy of Additional Power Contract dated
February 1, 1984. (Exhibit C-123, 1984 Form 10-K,
File No. 1-8222)

10.8.3 Amendment No. 3 to Vermont Yankee Power Contract,
dated April 24, 1985. (Exhibit 10-144, 1986 Form
10-K, File No. 1-8222)

10.8.4 Amendment No. 4 to Vermont Yankee Power Contract,
dated June 1, 1985. (Exhibit 10-145, 1986 Form 10-K,
File No. 1-8222)

10.8.5 Amendment No. 5 dated May 6, 1988. (Exhibit 10-179,
1988 Form 10-K, File No. 1-8222)

10.8.6 Amendment No. 6 dated May 6, 1988. (Exhibit 10-180,
1988 Form 10-K, File No. 1-8222)

10.8.7 Amendment No. 7 dated June 15, 1989. (Exhibit
10-195, 1989 Form 10-K, File No. 1-8222)

10.9 Copy of Capital Funds Agreement between the Company and Maine
Yankee dated as of May 20, 1968. (Exhibit C-14, File No.
70-4658)

10.9.1 Amendment No. 1 dated August 1, 1985. (Exhibit
C-125, 1984 Form 10-K, File No. 1-8222)

10.10 Copy of Power Contract between the Company and Maine Yankee
dated as of May 20, 1968. (Exhibit C-15, File No. 70-4658)

10.10.1 Amendment No. 1 dated March 1, 1984. (Exhibit
C-112, 1984 Form 10-K, File No. 1-8222)

10.10.2 Amendment No. 2 effective January 1, 1984.
(Exhibit C-113, 1984 Form 10-K, File No. 1-8222)

10.10.3 Amendment No. 3 dated October 1, 1984. (Exhibit
C-114, 1984 Form 10-K, File No. 1-8222)

10.10.4 Additional Power Contract dated February 1, 1984.
(Exhibit C-126, 1985 Form 10-K, File No. 1-8222)

10.11 Copy of Agreement dated January 17, 1968, between Velco and
Public Service Company of New Hampshire relating to purchase
of additional unit power from Merrimack II. (Exhibit C-16,
File No. 2-32917)

10.12 Copy of Agreement dated February 10, 1968 between the
Company and Velco relating to purchase by Company of
Merrimack II unit power. (There are 25 similar agreements
between Velco and other utilities.) (Exhibit C-17, File No.
2-32917)

10.13 Copy of Three-Party Power Agreement dated as of
November 21, 1969, among the Company, Velco, and Green
Mountain relating to purchase and sale of power from Vermont
Yankee Nuclear Power Corporation. (Exhibit C-18, File No.
2-38161)

10.13.1 Amendment dated June 1, 1981. (Exhibit 10.13.1,
1993 Form 10-K, File No. 1-8222)

10.14 Copy of Three-Party Transmission Agreement dated as of
November 21, 1969, among the Company, Velco, and Green
Mountain providing for transmission of power from Vermont
Yankee Nuclear Power Corporation. (Exhibit C-19, File No.
2-38161)

10.14.1 Amendment dated June 1, 1981. (Exhibit 10.14.1,
1993 Form 10-K, File No. 1-8222)

10.15 Copy of Stockholders Agreement dated September 25, 1957,
between the Company, Velco, Green Mountain and Citizens
Utilities Company. (Exhibit No. C-20, File No. 70-3558)

10.16 New England Power Pool Agreement dated as of
September 1, 1971, as amended to November 1, 1975. (Exhibit
C-21, File No. 2-55385)

10.16.1 Amendment dated December 31, 1976. (Exhibit
10.16.1, 1993 Form 10-K, File No. 1-8222)

10.16.2 Amendment dated January 23, 1977. (Exhibit
10.16.2, 1993 Form 10-K, File No. 1-8222)

10.16.3 Amendment dated July 1, 1977. (Exhibit 10.16.3,
1993 Form 10-K, File No. 1-8222)

10.16.4 Amendment dated August 1, 1977. (Exhibit 10.16.4,
1993 Form 10-K, File No. 1-8222)

10.16.5 Amendment dated August 15, 1978. (Exhibit 10.16.5,
1993 Form 10-K, File No. 1-8222)

10.16.6 Amendment dated January 31, 1979. (Exhibit
10.16.6, 1993 Form 10-K, File No. 1-8222)

10.16.7 Amendment dated February 1, 1980. (Exhibit
10.16.7, 1993 Form 10-K, File No. 1-8222)

10.16.8 Amendment dated December 31, 1976. (Exhibit
10.16.8, 1993 Form 10-K, File No. 1-8222)

10.16.9 Amendment dated January 31, 1977. (Exhibit
10.16.9, 1993 Form 10-K, File No. 1-8222)

10.16.10 Amendment dated July 1, 1977. (Exhibit 10.16.10,
1993 Form 10-K, File No. 1-8222)

10.16.11 Amendment dated August 1, 1977. (Exhibit 10.16.11,
1993 Form 10-K, File No. 1-8222)

10.16.12 Amendment dated August 15, 1978. (Exhibit
10.16.12, 1993 Form 10-K, File No. 1-8222)

10.16.13 Amendment dated January 31, 1980. (Exhibit
10.16.13, 1993 Form 10-K, File No. 1-8222)

10.16.14 Amendment dated February 1, 1980. (Exhibit
10.16.14, 1993 Form 10-K, File No. 1-8222)

10.16.15 Amendment dated September 1, 1981. (Exhibit
10.16.15, 1993 Form 10-K, File No. 1-8222)

10.16.16 Amendment dated December 1, 1981. (Exhibit
10.16.16, 1993 Form 10-K, File No. 1-8222)

10.16.17 Amendment dated June 15, 1983. (Exhibit 10.16.17,
1993 Form 10-K, File No. 1-8222)

10.16.18 Amendment dated September 1, 1985. (Exhibit
10-160, 1986 Form 10-K, File No. 1-8222)

10.16.19 Amendment dated April 30, 1987. (Exhibit 10-172,
1987 Form 10-K, File No. 1-8222)

10.16.20 Amendment dated March 1, 1988. (Exhibit 10-178,
1988 Form 10-K, File No. 1-8222)

10.16.21 Amendment dated March 15, 1989. (Exhibit 10-194,
1989 Form 10-K, File No. 1-8222)

10.16.22 Amendment dated October 1, 1990. (Exhibit 10-203,
1990 Form 10-K, File No. 1-8222)

10.16.23 Amendment dated September 15, 1992. (Exhibit
10.16.23, 1992 Form 10-K, File No. 1-8222)

10.16.24 Amendment dated May 1, 1993. (Exhibit 10.16.24,
1993 Form 10-K, File No. 1-8222)

10.16.25 Amendment dated June 1, 1993. (Exhibit 10.16.25,
1993 Form 10-K, File No. 1-8222)

10.16.26 Amendment dated June 1, 1994. (Exhibit 10.16.26,
1994 Form 10-K, File No. 1-8222)

10.16.27 Thirty-Second Amendment dated September 1, 1995.
(Exhibit 10.16.27, Form 10-Q dated
September 30, 1995, File No. 1-8222 and Exhibit
10.16.27, 1995 Form 10-K, File No. 1-8222)

10.17 Agreement dated October 13, 1972, for Joint Ownership,
Construction and Operation of Pilgrim Unit No. 2 among
Boston Edison Company and other utilities, including the
Company. (Exhibit C-23, File No. 2-45990)

10.17.1 Amendments dated September 20, 1973, and
September 15, 1974. (Exhibit C-24, File No.
2-51999)

10.17.2 Amendment dated December 1, 1974. (Exhibit C-25,
File No. 2-54449)

10.17.3 Amendment dated February 15, 1975. (Exhibit C-26,
File No. 2-53819)

10.17.4 Amendment dated April 30, 1975. (Exhibit C-27,
File No. 2-53819)

10.17.5 Amendment dated as of June 30, 1975. (Exhibit
C-28, File No. 2-54449)

10.17.6 Instrument of Transfer dated as of October 1, 1974,
assigning partial interest from the Company to
Green Mountain Power Corporation. (Exhibit C-29,
File No. 2-52177)

10.17.7 Instrument of Transfer dated as of
January 17, 1975, assigning a partial interest from
the Company to the Burlington Electric Department.
(Exhibit C-30, File No. 2-55458)

10.17.8 Addendum dated as of October 1, 1974 by which Green
Mountain Power Corporation became a party thereto.
(Exhibit C-31, File No. 2-52177)

10.17.9 Addendum dated as of January 17, 1975 by which the
Burlington Electric Department became a party
thereto. (Exhibit C-32, File No. 2-55450)

10.17.10 Amendment 23 dated as of 1975. (Exhibit C-50, 1975
Form 10-K, File No. 1-8222)

10.18 Agreement for Sharing Costs Associated with Pilgrim Unit
No.2 Transmission dated October 13, 1972, among Boston
Edison Company and other utilities including the Company.
(Exhibit C-33, File No. 2-45990)

10.18.1 Addendum dated as of October 1, 1974, by which
Green Mountain Power Corporation became a party
thereto. (Exhibit C-34, File No. 2-52177)

10.18.2 Addendum dated as of January 17, 1975, by which
Burlington Electric Department became a party
thereto. (Exhibit C-35, File No. 2-55458)

10.19 Agreement dated as of May 1, 1973, for Joint Ownership,
Construction and Operation of New Hampshire Nuclear Units
among Public Service Company of New Hampshire and other
utilities, including Velco. (Exhibit C-36, File No.
2-48966)

10.19.1 Amendments dated May 24, 1974, June 21, 1974,
September 25, 1974, October 25, 1974, and
January 31, 1975. (Exhibit C-37, File No.
2-53674)

10.19.2 Instrument of Transfer dated September 27, 1974,
assigning partial interest from Velco to the
Company. (Exhibit C-38, File No. 2-52177)

10.19.3 Amendments dated May 24, 1974, June 21, 1974, and
September 25, 1974. (Exhibit C-81, File No.
2-51999)

10.19.4 Amendments dated October 25, 1974 and
January 31, 1975. (Exhibit C-82, File No. 2-54646)

10.19.5 Sixth Amendment dated as of April 18, 1979.
(Exhibit C-83, File No. 2-64294)

10.19.6 Seventh Amendment dated as of April 18, 1979.
(Exhibit C-84, File No. 2-64294)

10.19.7 Eighth Amendment dated as of April 25, 1979.
(Exhibit C-85, File No. 2-64815)

10.19.8 Ninth Amendment dated as of June 8, 1979.
(Exhibit C-86, File No. 2-64815)

10.19.9 Tenth Amendment dated as of October 10, 1979.
(Exhibit C-87, File No. 2-66334 )

10.19.10 Eleventh Amendment dated as of December 15, 1979.
(Exhibit C-88, File No.2-66492)

10.19.11 Twelfth Amendment dated as of June 16, 1980.
(Exhibit C-89, File No. 2-68168)

10.19.12 Thirteenth Amendment dated as of December 31, 1980.
(Exhibit C-90, File No. 2-70579)

10.19.13 Fourteenth Amendment dated as of
June 1, 1982.(Exhibit C-104, 1982 Form 10-K, File
No. 1-8222)

10.19.14 Fifteenth Amendment dated April 27, 1984. (Exhibit
10-134, 1986 Form 10-K, File No. 1-8222)

10.19.15 Sixteenth Amendment dated June 15, 1984. (Exhibit
10-135, 1986 Form 10-K, File No. 1-8222)

10.19.16 Seventeenth Amendment dated March 8, 1985. (Exhibit
10-136, 1986 Form 10-K, File No. 1-8222)

10.19.17 Eighteenth Amendment dated March 14, 1986. (Exhibit
10-137, 1986 Form 10-K, File No. 1-8222)

10.19.18 Nineteenth Amendment dated May 1, 1986. (Exhibit
10-138, 1986 Form 10-K, File No. 1-8222)

10.19.19 Twentieth Amendment dated September 19, 1986.
(Exhibit 10-139, 1986 Form 10-K, File No. 1-8222)

10.19.20 Amendment No. 22 dated January 13, 1989. (Exhibit
10-193, 1989 Form 10-K, File No. 1-8222)

10.20 Transmission Support Agreement dated as of May 1, 1973,
among Public Service Company of New Hampshire and other
utilities, including Velco, with respect to New Hampshire
Nuclear Units. (Exhibit C-39, File No. 248966)

10.21 Sharing Agreement - 1979 Connecticut Nuclear Unit dated
September 1, 1973, to which the Company is a party. (Exhibit
C-40, File No. 2-50142)

10.21.1 Amendment dated as of August 1, 1974. (Exhibit
C-41, File No. 2-51999)

10.21.2 Instrument of Transfer dated as of
February 28, 1974, transferring partial interest
from the Company to Green Mountain. (Exhibit C-42,
File No. 2-52177)

10.21.3 Instrument of Transfer dated January 17, 1975,
transferring a partial interest from the Company to
Burlington Electric Department. (Exhibit C-43,
File No. 2-55458)

10.21.4 Amendment dated May 11, 1984. (Exhibit C-110, 1984
Form 10-K, File No. 1-8222)

10.22 Preliminary Agreement dated as of July 5, 1974, with respect
to 1981 Montague Nuclear Generating Units. (Exhibit C-44,
File No. 2-51733)

10.22.1 Amendment dated June 30, 1975. (Exhibit C-45, File
No. 2-54449)

10.23 Agreement for Joint Ownership, Construction and Operation of
William F. Wyman Unit No. 4 dated November 1, 1974, among
Central Maine Power Company and other utilities including
the Company. (Exhibit C-46, File No. 2-52900)

10.23.1 Amendment dated as of June 30, 1975. (Exhibit
C-47, File No. 2-55458)

10.23.2 Instrument of Transfer dated July 30, 1975,
assigning a partial interest from Velco to the
Company. (Exhibit C-48, File No. 2-55458)

10.24 Transmission Agreement dated November 1, 1974, among Central
Maine Power Company and other utilities including the
Company with respect to William F. Wyman Unit No. 4.
(Exhibit C-49, File No. 2-54449)

10.25 Copy of Power Contract between the Company and Yankee Atomic
dated as of June 30, 1959. (Exhibit C-61, 1981 Form 10-K,
File No. 1-8222)

10.25.1 Revision dated April 1, 1975. (Exhibit C-61, 1981
Form 10-K, File No. 1-8222)

10.25.2 Amendment dated May 6, 1988. (Exhibit 10-181, 1988
Form 10-K, File No. 1-8222)

10.25.3 Amendment dated June 26, 1989. (Exhibit 10-196,
1989 Form 10-K, File No. 1-8222)

10.25.4 Amendment dated July 1, 1989. (Exhibit 10-197,
1989 Form 10-K, File No. 1-8222)

10.25.5 Amendment dated February 1, 1992 (Exhibit 10.25.5,
1992 Form 10-K, File No. 1-8222)

10.26 Copy of Transmission Contract between the Company and Yankee
Atomic dated as of June 30, 1959. (Exhibit C-63, 1981 Form
10-K, File No. 1-8222)

10.27 Copy of Power Contract between the Company and Connecticut
Yankee dated as of June 1, 1964. (Exhibit C-64, 1981 Form
10-K, File No. 1-8222)

10.27.1 Supplementary Power Contract dated March 1, 1978.
(Exhibit C-94, 1982 Form 10-K, File No. 1-8222)

10.27.2 Amendment dated August 22, 1980. (Exhibit C-95,
1982 Form 10-K, File No. 1-8222)

10.27.3 Amendment dated October 15, 1982. (Exhibit C-96,
1982 Form 10-K, File No. 1-8222)

10.27.4 Second Supplementary Power Contract dated
April 30, 1984. (Exhibit C-115, 1984 Form 10-K,
File No. 1-8222)

10.27.5 Additional Power Contract dated April 30, 1984.
(Exhibit C-116, 1984 Form 10-K, File No. 1-8222)

10.28 Copy of Transmission Contract between the Company and
Connecticut Yankee dated as of July 1, 1964. (Exhibit C-65,
1981 Form 10-K, File No. 1-8222)

10.29 Copy of Capital Funds Agreement between the Company and
Connecticut Yankee dated as of July 1, 1964. (Exhibit C-66,
1981 Form 10-K, File No. 1-8222)

10.29.1 Copy of Capital Funds Agreement between the Company
and Connecticut Yankee dated as of
September 1, 1964. (Exhibit C-67, 1981 Form 10-K,
File No. 1-8222)

10.30 Copy of Five-Year Capital Contribution Agreement between the
Company and Connecticut Yankee dated as of November 1,
1980. (Exhibit C-68, 1981 Form 10-K, File No. 1-8222)

10.31 Form of Guarantee Agreement dated as of November 7, 1981,
among certain banks, Connecticut Yankee and the Company,
relating to revolving credit notes of Connecticut Yankee.
(Exhibit C-69, 1981 Form 10-K, File No. 1-8222)

10.32 Form of Guarantee Agreement dated as of November 13, 1981,
between The Connecticut Bank and Trust Company, as Trustee,
and the Company, relating to debentures of Connecticut
Yankee. (Exhibit C-70, 1981 Form 10-K, File No. 1-8222)

10.33 Form of Guarantee Agreement dated as of November 5, 1981,
between Bankers Trust Company, as Trustee of the Vernon
Energy Trust, and the Company, relating to Vermont Yankee
Nuclear Fuel Sale Agreement. (Exhibit C-71, 1981 Form 10-K,
File No. 1-8222)

10.34 Preliminary Vermont Support Agreement re Quebec
interconnection between Velco and among seventeen Vermont
Utilities dated May 1, 1981. (Exhibit C-97, 1982 Form 10-K,
File No. 1-8222)

10.34.1 Amendment dated June 1, 1982. (Exhibit C-98, 1982
Form 10-K, File No. 1-8222)

10.35 Vermont Participation Agreement for Quebec Interconnection
between Velco and among seventeen Vermont Utilities dated
July 15, 1982. (Exhibit C-99, 1982 Form 10-K, File No.
1-8222)

10.35.1 Amendment No. 1 dated January 1, 1986. (Exhibit
C-132, 1986 Form 10-K, File No. 1-8222)

10.36 Vermont Electric Transmission Company Capital Funds Support
Agreement between Velco and among sixteen Vermont Utilities
dated July 15, 1982. (Exhibit C-100, 1982 Form 10-K, File
No. 1-8222)

10.37 Vermont Transmission Line Support Agreement, Vermont
Electric Transmission Company and twenty New England
Utilities dated December 1, 1981, as amended by Amendment
No. 1 dated June 1, 1982, and by Amendment No. 2 dated
November 1, 1982. (Exhibit C-101, 1982 Form 10-K, File No.
1-8222)

10.37.1 Amendment No. 3 dated January 1, 1986. (Exhibit
10-149, 1986 Form 10-K, File No. 1-8222)

10.38 Phase 1 Terminal Facility Support Agreement between New
England Electric Transmission Corporation and twenty New
England Utilities dated December 1, 1981, as amended by
Amendment No. 1 dated as of June 1, 1982 and by Amendment
No. 2 dated as of November 1, 1982. (Exhibit C-102, 1982
Form 10-K, File No. 1-8222)

10.39 Power Purchase Agreement between Velco and CVPS dated
June 1, 1981. (Exhibit C-103, 1982 Form 10-K, File No.
1-8222)

10.40 Agreement for Joint Ownership, Construction and Operation of
the Joseph C. McNeil Generating Station by and between City
of Burlington Electric Department, Central Vermont Realty,
Inc. and Vermont Public Power Supply Authority dated
May 14, 1982. (Exhibit C-107, 1983 Form 10-K, File No.
1-8222)

10.40.1 Amendment No. 1 dated October 5, 1982. (Exhibit
C-108, 1983 Form 10-K, File No. 1-8222)

10.40.2 Amendment No. 2 dated December 30, 1983. (Exhibit
C-109, 1983 Form 10-K, File No. 1-8222)

10.40.3 Amendment No. 3 dated January 10, 1984. (Exhibit
10-143, 1986 Form 10-K, File No. 1-8222)

10.41 Transmission Service Contract between Central Vermont Public
Service Corporation and The Vermont Electric Generation &
Transmission Cooperative, Inc. dated May 14, 1984. (Exhibit
C-111, 1984 Form 10-K, File No. 1-8222)

10.42 Copy of Highgate Transmission Interconnection Preliminary
Support Agreement dated April 9, 1984. (Exhibit C-117, 1984
Form 10-K, File No. 1-8222)

10.43 Copy of Allocation Contract for Hydro-Quebec Firm Power
dated July 25, 1984. (Exhibit C-118, 1984 Form 10-K, File
No. 1-8222)

10.43.1 Tertiary Energy for Testing of the Highgate HVDC
Station Agreement, dated September 20, 1985.
(Exhibit C-129, 1985 Form 10-K, File No. 1-8222)

10.44 Copy of Highgate Operating and Management Agreement dated
August 1, 1984. (Exhibit C-119, 1986 Form 10-K, File No.
1-8222)

10.44.1 Amendment No. 1 dated April 1, 1985. (Exhibit
10-152, 1986 Form 10-K, File No. 1-8222)

10.44.2 Amendment No. 2 dated November 13, 1986. (Exhibit
10-167, 1987 Form 10-K, File No. 1-8222)

10.44.3 Amendment No. 3 dated January 1, 1987. (Exhibit
10-168, 1987 Form 10-K, File No. 1-8222)

10.45 Copy of Highgate Construction Agreement dated
August 1, 1984. (Exhibit C-120, 1984 Form 10-K, File No.
1-8222)

10.45.1 Amendment No. 1 dated April 1, 1985. (Exhibit
10-151, 1986 Form 10-K, File No. 1-8222)

10.46 Copy of Agreement for Joint Ownership, Construction and
Operation of the Highgate Transmission Interconnection.
(Exhibit C-121, 1984 Form 10-K, File No. 1-8222)

10.46.1 Amendment No. 1 dated April 1, 1985. (Exhibit
10-153, 1986 Form 10-K, File No. 1-8222)

10.46.2 Amendment No. 2 dated April 18, 1985. (Exhibit
10-154, 1986 Form 10-K, File No. 1-8222)

10.46.3 Amendment No. 3 dated February 12, 1986. (Exhibit
10-155, 1986 Form 10-K, File No. 1-8222)

10.46.4 Amendment No. 4 dated November 13, 1986. (Exhibit
10-169, 1987 Form 10-K, File No. 1-8222)

10.46.5 Amendment No. 5 and Restatement of Agreement dated
January 1, 1987. (Exhibit 10-170, 1987 Form 10-K,
File No. 1-8222)

10.47 Copy of the Highgate Transmission Agreement dated
August 1, 1984. (Exhibit C-122, 1984 Form 10-K, File No.
1-8222)

10.48 Copy of Preliminary Vermont Support Agreement Re: Quebec
Interconnection - Phase II dated September 1, 1984. (Exhibit
C-124, 1984 Form 10-K, File No. 1-8222)

10.48.1 First Amendment dated March 1, 1985. (Exhibit
C-127, 1985 Form 10-K, File No. 1-8222)

10.49 Vermont Transmission and Interconnection Agreement between
New England Power Company and Central Vermont Public
Service Corporation and Green Mountain Power Corporation
with the consent of Vermont Electric Power Company, Inc.,
dated May 1, 1985. (Exhibit C-128, 1985 Form 10-K, File No.
1-8222)

10.50 Service Contract Agreement between the Company and the State
of Vermont for distribution and sale of energy from St.
Lawrence power projects ("NYPA Power") dated as of
June 25, 1985. (Exhibit C-130, 1985 Form 10-K, File No.
1-8222)

10.50.1 Lease and Operating Agreement between the Company
and the State of Vermont dated as of
June 25, 1985. (Exhibit C-131, 1985 Form 10-K, File
No. 1-8222)

10.51 System Sales & Exchange Agreement Between Niagara Mohawk
Power Corporation and Central Vermont Public Service
Corporation dated October 1, 1986. (Exhibit C-133, 1986
Form 10-K, File No. 1-8222)

10.54 Transmission Agreement between Vermont Electric Power
Company, Inc. and Central Vermont Public Service Corporation
dated January 1, 1986. (Exhibit 10-146, 1986 Form 10-K,
File No. 1-8222)

10.55 1985 Four-Party Agreement between Vermont Electric Power
Company, Central Vermont Public Service Corporation, Green
Mountain Power Corporation and Citizens Utilities dated
July 1, 1985. (Exhibit 10-147, 1986 Form 10-K, File No.
1-8222)

10.55.1 Amendment dated February 1, 1987. (Exhibit 10-171,
1987 Form 10-K, File No. 1-8222)

10.56 1985 Option Agreement between Vermont Electric Power
Company, Central Vermont Public Service Corporation, Green
Mountain Power Corporation and Citizens Utilities dated
December 27, 1985. (Exhibit 10-148, 1986 Form 10-K, File
No. 1-8222)

10.56.1 Amendment No. 1 dated September 28, 1988. (Exhibit
10-182, 1988 Form 10-K, File No. 1-8222)

10.56.2 Amendment No. 2 dated October 1, 1991. (Exhibit
10.56.2, 1991 Form 10-K, File No. 1-8222)

10.56.3 Amendment No. 3 dated December 31, 1994. (Exhibit
10.56.3, 1994 Form 10-K, File No. 1-8222)

10.56.4 Amendment No. 4 dated December 31, 1996. (Exhibit
10.56.4, 1996 Form 10-K, file No. 1-8222)

10.57 Highgate Transmission Agreement dated August 1, 1984 by and
between the owners of the project and the Vermont electric
distribution companies. (Exhibit 10-156, 1986 Form 10-K,
File No. 1-8222)

10.57.1 Amendment No. 1 dated September 22, 1985. (Exhibit
10-157, 1986 Form 10-K, File No. 1-8222)

10.58 Vermont Support Agency Agreement re: Quebec Interconnection
- Phase II between Vermont Electric Power Company, Inc. and
participating Vermont electric utilities dated
June 1, 1985. (Exhibit 10-158, 1986 Form 10K, File No.
1-8222)

10.58.1 Amendment No. 1 dated June 20, 1986. (Exhibit
10-159, 1986 Form 10-K, File No. 1-8222)

10.59 Indemnity Agreement B-39 dated May 9, 1969 with amendments
1-16 dated April 17, 1970 thru April 16, 1985 between
licensees of Millstone Unit No. 3 and the Nuclear Regulatory
Commission. (Exhibit 10-161, 1986 Form 10-K, File No.
1-8222)

10.59.1 Amendment No. 17 dated November 25, 1985. (Exhibit
10-162, 1986 Form 10-K, File No. 1-8222)

10.62 Contract for the Sale of 50MW of firm power between
Hydro-Quebec and Vermont Joint Owners of Highgate Facilities
dated February 23, 1987. (Exhibit 10-173, 1987 Form 10-K,
File No. 1-8222)

10.63 Interconnection Agreement between Hydro-Quebec and Vermont
Joint Owners of Highgate facilities dated February 23,
1987. (Exhibit 10-174, 1987 Form 10-K, File No. 1-8222)

10.63.1 Amendment dated September 1, 1993 (Exhibit
10.63.1, 1993 Form 10-K, File No. 1-8222)

10.64 Firm Power and Energy Contract by and between Hydro-Quebec
and Vermont Joint Owners of Highgate for 500MW dated
December 4, 1987. (Exhibit 10-175, 1987 Form 10-K, File No.
1-8222)

10.64.1 Amendment No. 1 dated August 31, 1988. (Exhibit
10-191, 1988 Form 10-K, File No. 1-8222)

10.64.2 Amendment No. 2 dated September 19, 1990. (Exhibit
10-202, 1990 Form 10-K, File No. 1-8222)

10.64.3 Firm Power & Energy Contract dated January 21, 1993
by and between Hydro-Quebec and Central Vermont
Public Service Corporation for the sale back of 25
MW of power. (Exhibit 10.64.3, 1992 Form 10-K,
File No. 1-8222)

10.64.4 Firm Power & Energy Contract dated January 21, 1993
by and between Hydro-Quebec and Central Vermont
Public Service Corporation for the sale back of 50
MW of power. (Exhibit 10.64.4, 1992 Form 10-K,
File No. 1-8222)

10.66 Hydro-Quebec Participation Agreement dated April 1, 1988 for
600 MW between Hydro-Quebec and Vermont Joint Owners of
Highgate. (Exhibit 10-177, 1988 Form 10-K, File No. 1-8222)

10.66.1 Hydro-Quebec Participation Agreement dated April 1,
1988 as amended and restated by Amendment No. 5
thereto dated October 21, 1993, among Vermont
utilities participating in the purchase of
electricity under the Firm Power and Energy
Contract by and between Hydro-Quebec and Vermont
Joint Owners of Highgate. (Exhibit 10.66.1, 1997
Form 10-Q, March 31, 1997, File. No. 1-8222)

10.67 Sale of firm power and energy (54MW) between Hydro-Quebec
and Vermont Utilities dated December 29, 1988. (Exhibit
10-183, 1988 Form 10-K, File No. 1-8222)

10.75 Receivables Purchase Agreement between Central Vermont
Public Service Corporation, Central Vermont Public Service
Corporation as Service Agent and The First National Bank of
Boston dated November 29, 1988. (Exhibit 10-192, 1988 Form
10-K) 10.75.1 Agreement Amendment No. 1 dated
December 21, 1988 Exhibit 10.75.1, 1993 Form 10-K, File No.
1-8222)

10.75.2 Letter Agreement dated December 4, 1989
(Exhibit 10.75.2, 1993 Form 10-K, File No. 1-8222)

10.75.3 Agreement Amendment No. 2 dated November 29, 1990
(Exhibit 10.75.3, 1993 Form 10-K, File No. 1-8222)

10.75.4 Agreement Amendment No. 3 dated November 29, 1991
(Exhibit 10.75.4, 1993 Form 10-K, File No. 1-8222)

10.75.5 Agreement Amendment No. 4 dated November 29, 1992
(Exhibit 10.75.5, 1993 Form 10-K, File No. 1-8222)

10.75.6 Agreement Amendment No. 5 dated November 29, 1993
(Exhibit 10.75.6, 1997 Form 10-K, File No. 1-8222)

10.75.7 Agreement Amendment No. 6 dated November 29, 1994
(Exhibit 10.75.7, 1997 Form 10-K, File No. 1-8222)

10.75.8 Agreement Amendment No. 7 dated November 29, 1995
(Exhibit 10.75.8, 1997 Form 10-K, File No. 1-8222)

10.75.9 Agreement Amendment No. 8 dated February 5, 1997
(Exhibit 10.75.9, 1997 Form 10-K, File No. 1-8222)

10.75.10 Agreement Amendment No. 9 dated February 2, 1998
(Exhibit 10.75.10, 1997 Form 10-K, File No. 1-8222)

10.83 Credit Agreement Dated As of November 5, 1997, see exhibit
4-56; 10.83.1 and 10.83.2, see exhibit 4-56.1 and 4-56.2.

EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS

A 10.68 Stock Option Plan for Non-Employee Directors dated
July 18, 1988. (Exhibit 10-184, 1988 Form 10-K, File No.
1-8222)

A 10.69 Stock Option Plan for Key Employees dated July 18, 1988.
(Exhibit 10-185, 1988 Form 10-K, File No. 1-8222)

A 10.70 Officers Supplemental Insurance Plan authorized
July 9, 1984. (Exhibit 10-186, 1988 Form 10-K, File No.
1-8222)

A 10.71 Officers Supplemental Deferred Compensation Plan dated
November 4, 1985. (Exhibit 10-187, 1988 Form 10-K, File
No. 1-8222)

A 10.71.1 Amendment dated October 2, 1995. (Exhibit
10.71.1, 1995 Form 10-K, File No. 1-8222)

A 10.72 Directors' Supplemental Deferred Compensation Plan dated
November 4, 1985. (Exhibit 10-188, 1988 Form 10-K, File No.
1-8222)

A 10.72.1 Amendment dated October 2, 1995. (Exhibit
10.72.1, 1995 Form 10-K, File No. 1-8222)

A 10.73 Management Incentive Compensation Plan as adopted
September 9, 1985. (Exhibit 10-189, 1988 Form 10-K, File
No. 1-8222)

A 10.73.1 Revised Management Incentive Plan as adopted
February 5, 1990. (Exhibit 10-200, 1989 Form 10-K,
File No. 1-8222)

A 10.73.2 Revised Management Incentive Plan dated
May 2, 1995. (Exhibit 10.73.2, 1995 Form 10-K, File No.
1-8222)

A 10.74 Officers' Change of Control Agreements as approved
October 3, 1988. (Exhibit 10-190, 1988 Form 10-K, File No.
1-8222)

A 10.78 Stock Option Plan for Non-Employee Directors dated
April 30, 1993 (Exhibit 10.78, 1993 Form 10-K, File No.
1-8222)

A 10.79 Officers Insurance Plan dated November 15, 1993
(Exhibit 10.79, 1993 Form 10-K, File No. 1-8222)

A 10.79.1 Amendment dated October 2, 1995. (Exhibit No.
10.79.1, 1995 Form 10-K, File No. 1-8222)

A 10.80 Directors' Supplemental Deferred Compensation Plan dated
January 1, 1990 (Exhibit 10.80, 1993 Form 10-K, File No.
1-8222)

A 10.80.1 Amendment dated October 2, 1995. (Exhibit No.
10.80.1, 1995 Form 10-K, File No. 1-8222)

A 10.81 Officers' Supplemental Deferred Compensation Plan dated
January 1, 1990 (Exhibit 10.81, 1993 Form 10-K, File No.
1-8222)

A 10.82 Management Incentive Plan for Executive Officers dated
January 1, 1997. (Exhibit 10.82, 1996 Form 10-K, File No.
1-8222)

A 10.83 Management Incentive Plan for Executive Officers dated
January 1, 1998 (Exhibit A10.83, Form 10-Q, March 31, 1998,
File No. 1-8222)

A 10.84 Officers' Change of Control Agreement dated January 1, 1998
(Exhibit 10.84, 1998 Form 10-K, File No. 1-8222)

A 10.85 Officers' Supplemental Retirement and Deferred Compensation
Plan as Amended and Restated Effective January 1, 1998
(Exhibit 10.85, 1998 Form 10-K, File No. 1-8222)

A 10.86 1993 Stock Option Plan for Non-employee Directors (Exhibit
28 to Registration Statement, Registration 33-62100)

A 10.87 1997 Stock Option Plan for Key Employees (Exhibit 4.3 to
Registration Statement, Registration 333-57001)

A 10.88 1997 Restricted Stock Plan for Non-employee Directors
and Key Employees (Exhibit 4.3 to Registration Statement,
Registration 333-57005)

A 10.89 Management Incentive Plan for Executive Officers dated
January 1, 1999. (Exhibit A10.89, Form 10-Q, March 31, 1999,
File No. 1-8222)
A 10.90 Performance Share Incentive Plan dated effective
January 1, 1999. (Exhibit A10.90, Form 10-Q, June 30, 1999,
File No. 1-8222)

A - Compensation related plan, contract, or arrangement.

21. Subsidiaries of the Registrant

* 21.1 List of Subsidiaries of Registrant

23. Consents of Experts and Counsel

* 23.1 Consent of Independent Public Accountants

24. Power of Attorney

* 24.1 Powers of Attorney executed by Directors and Officers of
Company

27. Financial Data Schedule (filed electronically only)

(b) Reports on Form 8-K:

There were no reports on Form 8-K for the quarter ended
December 31, 1999.

<PAGE>

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors of
Central Vermont Public Service Corporation:

We have audited, in accordance with generally accepted auditing
standards, the consolidated financial statements included in Central
Vermont Public Service Corporation's annual report to shareholders,
included in this Form 10-K, and have issued our report thereon dated
February 7, 2000, (except with respect to the matter discussed in Note
13, as to which the date is March 6, 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 index above is the responsibility
of the Company's management and is presented for purposes of complying
with the Securities and Exchange Commission's rules and is not part of
the basic 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 consolidated financial data required to be set forth
therein in relation to the basic consolidated financial statements taken
as a whole.

ARTHUR ANDERSEN LLP

Boston, Massachusetts
February 7, 2000 (except
with respect to the
matter discussed in
Note 13, as to which
the date is March 6, 2000).

<PAGE>

Schedule II

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES

Reserves

Year ended December 31, 1999
<TABLE>
<CAPTION>

Additions
--------------------
Balance at Charged to Charged Balance at
beginning costs and to other end of
of year expenses accounts Deductions year
---------- ---------- -------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Reserves deducted from assets
to which they apply:

$112,145(1)
Reserve for uncollectible 310,145(2)
--------
accounts receivable $2,241,796 $1,350,731 $422,290 $2,419,384(3) $1,595,433
========== ========== ======== ========== ==========

Accumulated depreciation of
miscellaneous properties:

Rental water heater program $3,718,075 $350,003 - $ 255,033(4) $3,813,045

Other 18,460(5)
572,908 70,087 - 94,294(6) 530,241
---------- -------- ---------- ----------
$4,290,983 $420,090 $ 367,787 $4,343,286
========== ======== =========== ==========

Reserves shown separately:

Injuries and damages reserve $ 225,580 - - - $ 225,580
========== ==========

Environmental Reserve $9,947,104 - $ 40,380(7) $ 179,170(8) $9,808,314
========== ======== ========== ==========
Company Restructuring $4,363,453 - $1,215,821(8) $3,147,632
========== ======== ========== ==========
Accumulated provision for
rate refunds $2,737,345 $ 73,004 - $ 181,870(9) $2,628,479
========== ======== ======== ========== ==========
</TABLE>

(1) Amount due from collection agency
(2) Collections of accounts previously written off
(3) Uncollectible accounts written off
(4) Retirements of rental water heaters
(5) Write down of computers
(6) Sale of Service Center
(7) Additional Reserve
(8) Expenses charged against reserve
(9) Rate refund charged against reserve

<PAGE>
<TABLE>
<CAPTION>
Schedule II

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES

Reserves

Year ended December 31, 1998

$ 77,925(1)
Reserve for uncollectible 354,950(2)
----------
accounts receivable $1,945,893 $1,126,136 $ 432,875 $1,263,108(3) $2,241,796
========== ========== ========== ========== ==========

Accumulated depreciation of
miscellaneous properties:

Rental water heater program $3,629,089 $ 360,158 - $ 271,172(4) $3,718,075

Other 24,918(5)
365,134 242,677 - 9,985(6) 572,908
---------- ---------- ---------- ----------
$3,994,223 $ 602,835 $ 306,075 $4,290,983
========== ========== ========== ==========

Reserves shown separately:

Injuries and damages reserve $ 225,580 - - - $ 225,580
========== ==========
Environmental Reserve $4,367,151 $ 500,000 $5,532,871(7) $ 452,918(8) $9,947,104
========== ========== ========== ========== ==========

Company Restructuring $7,659,464 $3,296,011(8) $4,363,453
========== ========== ==========
Accumulated provision for
rate refunds - $2,737,345 - - $2,737,345
========== ==========

</TABLE>

(1) Amount due from collection agency
(2) Collections of accounts previously written off
(3) Uncollectible accounts written off
(4) Retirements of rental water heaters
(5) Write down of computers
(6) Retirement of equipment
(7) Additional Reserve
(8) Expenses charged against reserve

<PAGE>
<PAGE>
<TABLE>
<CAPTION>
Schedule II

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES

Reserves

Year ended December 31, 1997

$ 91,909(1)
415,992(2)
Reserve for uncollectible 770,496(3)
----------
accounts receivable $1,132,195 $ 751,530 $1,278,397 $1,216,229(4) $1,945,893
========== ========= ========== ========== ==========

Accumulated depreciation of
miscellaneous properties:

Rental water heater program $3,553,149 $ 357,961 - $ 282,021(5) $3,629,089

320,811(6)
Other 731,892 106,248 - 152,195(7) 365,134
---------- --------- ---------- ---------
$4,285,041 $ 464,209 $ 755,027 $3,994,223
========== ========= ========== ==========

Reserves shown separately:

Injuries and damages reserve $ 225,580 - - - $ 225,580
========== ==========
Environmental Reserve $5,176,725 - $ 809,574(8) $4,367,151
========== ========== ==========
Company Restructuring - $7,720,578 - $ 61,114(8) $7,659,464
========== ========== ==========

</TABLE>

(1) Amount due from collection agency
(2) Collections of accounts previously written off
(3) Transferred from miscellaneous receivables
(4) Uncollectible accounts written off
(5) Retirement/Sale of rental water heaters
(6) Sale of non-utility Property
(7) Amortization of Customer Information Systems
(8) Expenses charged against reserve

<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.

CENTRAL VERMONT PUBLIC SERVICE
CORPORATION

By /s/ Robert H. Young
Robert H. Young, President and
Chief Executive Officer

March 10,2000

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 indicated on March 10, 2000.

Signature Title

/s/ Robert H. Young President and Chief Executive Officer and
(Robert H. Young) Director

/s/ Francis J. Boyle Senior Vice President, Chief Financial
(Francis J. Boyle) Officer and Treasurer (Principal
Financial Officer)

/s/ James M. Pennington Vice President, Controller (Principal
(James M. Pennington) Accounting Officer)

Frederic H. Bertrand* Chairman of the Board and Director

Robert L. Barnett* Director

Rhonda L. Brooks* Director

Robert G. Clarke* Director

Luther F. Hackett* Director

Patrick . Martin* Director

Mary Alice McKenzie* Director

Janice L. Scites* Director

By: /s/ Robert H. Young
(Robert H. Young)

Attorney-in-Fact for each of the persons indicated.

* Such signature has been affixed pursuant to a Power of Attorney
filed as an exhibit hereto and incorporated herein by reference
thereto.

EXHIBIT 21.1

Subsidiaries of the Registrant

State in Which
Incorporated

Connecticut Valley Electric Company Inc. (a) (F1) New Hampshire

Vermont Electric Power Company, Inc. (b) (F2) Vermont

C.V. Realty, Inc. (a) (F1) Vermont

Central Vermont Public Service Corporation -
East Barnet Hydroelectric, Inc. (a) (F1) Vermont

Catamount Resources Corporation (a) (F1) Vermont

Catamount Energy Corporation (a)(c) (F1) Vermont

SmartEnergy Services, Inc. (a)(d) (F1) Vermont

- - - - - - - - - - - - - - - - - - - - - - - - - - - -

(FN)
(F1) (a) Included in consolidated financial statements

(F2) (b) Separate financial statements do not need to be filed
under Regulation S-X, Rule 1-02 (v) defining a
"significant subsidiary", and Rule 3-09, which sets
forth the requirement for filing separate financial
statements of subsidiaries not consolidated.

(c) Catamount Energy Corporation has eleven wholly-owned
subsidiaries, including nine operating in the United
States, and two operating in foreign countries.

(d) SmartEnergy Services, Inc. has three wholly-owned
subsidiaries operating in the United States.

EXHIBIT 23.1

CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS

As independent public accountants, we hereby consent to the
incorporation of our reports dated February 7, 2000 (except with respect
to the matter discussed in Note 13, as to which the date is March 6,
2000) included in this Form 10-K, into Central Vermont Public Service
Corporation's previously filed Registration Statement Form S-3, File No.
33-39691 and Form S-8 Registration Statements, No. 33-22741, No.
33-22742, No. 33-58102, No. 33-62100, No. 333-57001, No. 333-57005 and
No. 333-77217.

ARTHUR ANDERSEN LLP

Boston, Massachusetts
March 8, 2000

EXHIBIT 24.1

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that the undersigned Chief
Executive Officer, Chief Financial Officer and Treasurer, and Vice
President and Controller and the undersigned Directors of Central
Vermont Public Service Corporation, a Vermont Corporation, which
corporation proposes to file with the Securities and Exchange Commission
an Annual Report on Form 10-K for the year ended December 31, 1999,
under the Securities Exchange Act of 1934, as amended, does each for
himself/herself and not for one another, hereby constitute and appoint
Robert H. Young and Francis J. Boyle and each of them, his/her true and
lawful attorneys, in his/her name, place and stead, to sign his/her name
to said proposed Annual Report on Form 10-K and any and all amendments
thereto, and to cause the same to be filed with the Securities and
Exchange Commission, it being intended to grant and hereby granting to
said individuals, and each of them, full power and authority to do and
perform any act and thing necessary and proper to be done in the
premises as fully and to all intents and purposes as the undersigned
could do regarding the preparation, execution, filing of Form 10-K.

IN WITNESS WHEREOF, each of the undersigned has hereunto set their
hand as of the 7th day of February, 2000.

/s/ Robert H. Young /s/ Frederic H. Bertrand
Robert H. Young Frederic H. Bertrand
Chief Executive Officer and Director Chairman of the Board of
Directors

/s/ Francis J. Boyle /s/ Robert L. Barnett
Francis J. Boyle Robert L. Barnett, Director
Chief Financial Officer and Treasurer

/s/ James M. Pennington /s/ Rhonda L. Brooks
James M. Pennington Rhonda L. Brooks, Director
Vice President and Controller

/s/ Robert G. Clarke
Robert G. Clarke, Director

/s/ Luther F. Hackett
Luther F. Hackett, Director

/s/ Patrick J. Martin
Patrick J. Martin, Director

/s/ Mary Alice McKenzie
Mary Alice McKenzie, Director

/s/ Janice L. Scites
Janice L. Scites, Director

<ARTICLE> UT
<LEGEND>
This Financial Data Schedule contains summary financial information extracted
from the Consolidated Financial Statements included herein and is qualified in
its entirety by reference to such financial statements (dollars in thousands,
except per share amounts).
</LEGEND>

<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 314,732
<OTHER-PROPERTY-AND-INVEST> 73,283
<TOTAL-CURRENT-ASSETS> 106,160
<TOTAL-DEFERRED-CHARGES> 69,784
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 563,959
<COMMON> 66,556
<CAPITAL-SURPLUS-PAID-IN> 45,340
<RETAINED-EARNINGS> 72,371
<TOTAL-COMMON-STOCKHOLDERS-EQ> 184,021
17,000
8,054
<LONG-TERM-DEBT-NET> 155,251
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 16,688
0
<CAPITAL-LEASE-OBLIGATIONS> 15,060
<LEASES-CURRENT> 1,094
<OTHER-ITEMS-CAPITAL-AND-LIAB> 166,791
<TOT-CAPITALIZATION-AND-LIAB> 563,959
<GROSS-OPERATING-REVENUE> 419,815
<INCOME-TAX-EXPENSE> 10,360
<OTHER-OPERATING-EXPENSES> 384,804
<TOTAL-OPERATING-EXPENSES> 395,164
<OPERATING-INCOME-LOSS> 24,651
<OTHER-INCOME-NET> 4,091
<INCOME-BEFORE-INTEREST-EXPEN> 28,742
<TOTAL-INTEREST-EXPENSE> 12,158
<NET-INCOME> 16,584
1,862
<EARNINGS-AVAILABLE-FOR-COMM> 14,722
<COMMON-STOCK-DIVIDENDS> 10,099
<TOTAL-INTEREST-ON-BONDS> 8,710
<CASH-FLOW-OPERATIONS> 31,232
<EPS-BASIC> 1.28
<EPS-DILUTED> 1.28

</TABLE>