10-K405

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, 2001
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 (State of other jurisdiction incorporation or organization)	03-0111290 (IRS Employer Identification No.)
77 Grove Street, Rutland, Vermont (Address of principal executive offices)		05701 (Zip Code)
Registrant's telephone number, including area code			(802) 773-2711

Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Name of each exchange on which 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.  [    ]

Cover page

     State the aggregate market value of the voting stock held by non-affiliates of the registrant:  $202,425,109 based upon the closing price as of January 31, 2002 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, 2002, there were outstanding 11,633,627 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 7, 2002 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 - 2001

TABLE OF CONTENTS

		Page
PART I
Item 1. Item 2. Item 3. Item 4.	Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Submission of Matter to a Vote of Security Holders . . . . . . . . . . . . . . . . . . . . . . . . . . . .	2 19 20 20
PART II
Item 5. Item 6. Item 7. Item 8. Item 9.	Market for the Registrant's Common Equity and Related   Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Management's Discussion and Analysis of Financial   Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Changes in and Disagreements with Accountants on   Accounting and Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	21 22 23 43 79
PART III
Item 10. Item 11. Item 12. Item 13.	Directors and Executive Officers of the Registrant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Security Ownership of Certain Beneficial Owners and   Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Certain Relationships and Related Transactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	79 79 79 79
PART IV
Item 14. Signatures	Exhibits, Financial Statement Schedules, and Reports   on Form 8-K . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	80 100

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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 143,816 customers in nearly three-quarters of the towns, villages and cities in Vermont. 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 75% of total mWh sales for 2001. 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 resale firm sales accounted for approximately 5%, entitlement sales accounted for 6% and other resale sales which include contract sales, opportunity sales, sales to ISO-New England and short-term system capacity sales accounted for approximately 14% of total mWh sales for 2001.

     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 10,454 customers in 13 communities in New Hampshire. 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 2001. Sales to its five largest retail customers during the same period aggregated about 19% of Connecticut Valley's total electric revenues for 2001.

     The Company 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, as of December 31, 2001, the Company owned 31.3% of the common stock of Vermont Yankee Nuclear Power Corporation ("Vermont Yankee"), a nuclear generating company. The Company's ownership percentage in Vermont Yankee has changed to 33.23% in the first quarter of 2002 related to the buy-back of shares held by minority owners of the plant. 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 outstand ing common stock of Yankee Atomic Electric Company. See Part II Item 8, Note 2, for additional information.

     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.

     The Company also 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. See PART II Item 7, and Item 8, Notes 3 and 15, for additional information regarding the Company's diversification activities.

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 related to 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 ("NHPUC") as to matters pertaining to construction

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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 1159 mW nuclear generating facility, respectively.

     Connecticut Valley is subject to the regulatory authority of the 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 eight 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

     The Company is subject to environmental regulations in the licensing and operation of the generation, transmission, and distribution facilities in which it has an 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 may impact 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 ratemaking process. For additional information see Part II Item 8, Note 13, 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, and 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, Notes 2 and 13, herein for disclosures relating to the decommissioning of the Maine Yankee, Connecticut Yankee and Yankee Atomic nuclear power plants.

Competition

     Competition currently 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. 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.

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     An amendment to 30 V.S.A. Section 212(a) enacted May 28, 1987 authorizes the Vermont Department of Public Service ("DPS") 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 DPS if they are satisfied that the benefits outweigh any potential risk to the State. However, the DPS may proceed to file the retail proposal with the PSB either upon approval by the review board or the failure of the PSB to act within sixty (60) days of the submission. Section 212(c) provides that the DPS 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 eco nomic 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 DPS 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 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 PSB after a hearing. If either party is dissatisfied, the statute allows them to appeal the PSB'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.

     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, automatic delivery 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 convenience, the cost of back-up power sources, space requirements, noise problems, air emission and siting permit issues, and maintenance requirements.

The electric utility industry is in a period of transition that may result in a shift away from ratemaking 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. Recent events, including those related to restructuring in California and uncertainties concerning the operations of the wholesale markets in New England, have resulted in a slowdown of the restructuring process in Vermont. Furthermore, the PSB has terminated proceedings in Docket No. 6330, through which the PSB considered the establishment of policies and procedures to govern retail competition within the Company's Vermont service territory.

     For a further discussion relating to Electric Industry Restructuring in Vermont and New Hampshire see PART II Item 7, herein. See Wholesale Rates below, for a discussion relating to the Company's wholesale electric business.

RATE DEVELOPMENTS

Vermont Retail Rates

     1997 Retail Rate Case: 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.

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     In response to the Company's September 1997 rate increase 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 argued its posi tion before the Vermont Supreme Court.

     1998 Retail Rate Case: On June 12, 1998, the Company filed with the PSB for a 10.7% retail rate increase that supplanted the September 22, 1997 rate increase request of 6.6%, 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 was subject to retroactive or prospective adjustment upon future resolution of issues arising under the Hydro-Quebec and Vermont Joint Owner's ("VJO") Power Contract. The agreement temporarily disallowed approximately $7.4 million (based on 1999 power costs) for the Company's purchased power costs under the VJO Power Contract. As a result of the 4.7% rate increase agreement, during the fourth quarters of 1998 and 1999, the Company recorded pre-tax losses of $7.4 million and $2.9 million, respectively, 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 1999 and the first quarter of 2000, respectively. In 2000, an additional $11.5 million pre-tax loss was recorded for the estimated under-recovery of Hydro-Quebec power costs for the second, third and fourth quarters of 2000, and the first quarter of 2001. In the first quarter of 2001, an additional $2.9 million pre-tax loss was recorded for the estimated under-recovery of Hydro-Quebec power costs for the second quarter of 2001. In the second quarter of 2001, the Company reversed its $2.9 million pre-tax liability related to estimated under-recovery of Hydro-Quebec power costs and discontinued the accrual based on the favorable outcome of the Company's June 26, 2001 rate order, which is described below.

     2000 Retail Rate Case: In an effort to mitigate eroding earnings and cash flow prospects in the future, due mainly to under-recovery of power costs, on November 9, 2000, the Company filed with the PSB a request for a 7.6% rate increase ($19.0 million of annualized revenues) effective July 24, 2001. The PSB suspended the rate filing and a schedule was set to review the case.

     On February 9, 2001, the Vermont Supreme Court issued a decision on the Company's 1998 rate case appeal that reversed the PSB's decision on the preclusion issues and remanded the case to the PSB for further proceedings consistent with the Vermont Supreme Court's decision.

     The Company's June 26, 2001 rate order, which is described below, ended the uncertainty over the future recovery of Hydro-Quebec contract costs and the Company will no longer incur future losses for under-recovery of Hydro-Quebec contract costs related to any allegations of imprudence prior to the June 26, 2001 rate order.

     On May 7, 2001, the Company and the DPS reached a rate case settlement that would end uncertainty over the future recovery of Hydro-Quebec contract costs, allow a 3.95 % rate increase, make the January 1, 1999 temporary rates permanent, permit a return on equity of 11% for the twelve months ending June 30, 2002 for the Vermont utility, and create new service quality standards. The Company also agreed to a second quarter $9.0 million one-time write-off ($5.3 million after-tax) of regulatory assets and a rate freeze through January 1, 2003.

     On June 26, 2001, the PSB issued an order on the Company's rate case settlement with the DPS. In addition to the provisions outlined above, the approved rate order requires the Company to return up to $16.0 million to ratepayers in the event of a merger, acquisition or asset sale if such sale requires PSB approval. As a result of the rate order, the 3.95% rate increase became effective with bills rendered July 1, 2001, and in June 2001 the Company recorded a $5.3 million after-tax loss to write off certain regulatory assets as agreed to in the settlement. The Company was able to accept the 3.95% rate increase versus the 7.6% increase it requested since 1) regulatory asset amortizations will decrease approximately $3.5 million, on a twelve-month basis, due to the $9.0 million one-time

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write-off of regulatory assets and 2) Vermont Yankee decommissioning costs decreased approximately $1.9 million, on a twelve-month basis, after the rate case was filed as a result of an agreement in principle between Vermont Yankee and the secondary purchasers.

     Deseasonalized Rates: On June 8, 2000, the PSB approved the Company's request to end the winter-summer rate differential and, therefore, the Company now has flat rates throughout a given year. Winter rates were reduced by 14.9%, while summer rates were increased by 10.5%. The rate design change was revenue neutral over a twelve-month period. The additional revenues in 2000, resulting from implementing this change in mid-year, were applied to reduce regulatory deferrals related to the Hydro-Quebec ice storm arbitration, as directed by the PSB.

     Also see PART II Item 7, and Item 8, Note 12 herein.

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. The reconciliation for 2001 was an under-collection of $260,834 for the FAC and an over-collection of $812,472 for the PPCA. The reconciliation for 2000 was an under-collection of $828,379 for the FAC and an under-collection of $470,730 for the PPCA.

     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 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 2001 and 2002.

     On February 27, 2002, Connecticut Valley filed for approval to provide Energy Efficiency programs beginning June 1, 2002 and to recover the costs of such programs. An order is expected in the near future.

     As part of its restructuring plan, the New Hampshire legislature enacted an Electricity Consumption Tax on customers and repealed the New Hampshire Franchise Tax on utilities, both of which became effective May 1, 2001. Since the Franchise Tax, as a credit to the New Hampshire Business Profits Tax, was larger than the Business Profits Tax, the repeal of the Franchise Tax caused Connecticut Valley to incur the Business Profits Tax. The NHPUC approved a settlement that reduced base rates to remove recovery of the Franchise Tax and implemented a Business Profits Tax Percentage Adjustment that would be subject to annual revisions in order to collect the Business Profits Tax.

     On December 31, 2001, the NHPUC ruled on Connecticut Valley's request for a Temporary Billing Surcharge to recover approximately $1.7 million of one-time costs primarily related to industry restructuring effective January 1, 2002. Connecticut Valley had proposed the Temporary Billing Surcharge to exactly offset a contemporaneously filed FAC/PPCA decrease of 9.3% such that a zero rate change would occur at January 1, 2002 and the 9.3% FAC/PPCA decrease would occur when the Temporary Billing Surcharge terminated in November 2002. The NHPUC affirmed its prior policy of considering recovery of costs related to industry restructuring at the time retail choice is implemented in the Connecticut Valley service area. Thus the NHPUC deferred action on all but $125,000, for which recovery was allowed through November 30, 2002.

     On December 31, 2001 the NHPUC approved Connecticut Valley's FAC and PPCA rates for 2002 as well as Connecticut Valley's Business Profits Tax Adjustment Percentage and Conservation and Load Management Percentage Adjustment for 2002. Combined with the Temporary Billing Surcharge, the result was an overall 8.6% rate reduction with a revenue decrease of $1.8 million.

     In the third quarter of 2001, Management determined that Connecticut Valley is again subject to cost-based ratemaking and qualifies for the application of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" ("SFAS No. 71"). This decision was based on the favorable Court of Appeals decision of July 25, 2000 and the subsequent denial of the NHPUC's petition for writ of certiorari by the United States Supreme Court on February 20, 2001 as well as other regulatory developments in New Hampshire during 2001. The application of SFAS No. 71 resulted in an extraordinary charge of $0.2 million for Connecticut Valley. In 1998, Management had

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discontinued the application of SFAS No. 71 related to Connecticut Valley based on various legal and regulatory actions at the time. See PART II Item 8, Note 12 herein for information regarding New Hampshire Retail Rate/Federal Court Proceedings.

     Independent Power Producers Connecticut Valley purchases power from several Independent Power Producers, who own qualifying facilities as defined by the Public Utility Regulatory Policies Act of 1978. In 2001, under long-term contracts with these qualifying facilities, Connecticut Valley purchased 38,890 mWh, of which 96% was purchased from Wheelabrator Claremont Company, L.P., ("Wheelabrator") who owns a waste-to-energy electric generating facility. Connecticut Valley had filed a complaint with the FERC stating its concern that Wheelabrator has not been a qualifying facility since the facility began operation. On February 11, 1998, the FERC issued an Order denying Connecticut Valley's request for a refund of past purchased power costs and lower future costs. Connecticut Valley filed a request for rehearing with the FERC on March 13, 1998, which was denied. Connecticut Valley appealed to the D.C. Circuit Court of Appeals, which denied the appeal, but indicated th at Connecticut Valley could seek relief from the NHPUC. On May 12, 2000, Connecticut Valley filed a petition with the NHPUC seeking (1) to amend the contract to permit purchase of net, rather than gross, output of the facility and (2) a refund, with interest, of past purchases of the difference between net and gross output. See Part II Item 8, Note 12 for additional information related to the Wheelabrator contract.

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 capacity rates, as well as a subsequent reconciliation to actual data. The Company filed and the FERC approved 1) a revenue increase of $139,000, or 1.2%, for 2001 power costs; 2) a reconciliation of 2000 revenues to actual costs which resulted in a refund of $879,000, including interest; and 3) a revenue decrease of $1,983,000, or 15.1%, for 2002 power costs. A significant portion of the 2002 power cost decrease will be partially offset by a significant increase in monthly energy charges, related to the sale of Vermont Yankee, as discussed below.

     On February 28, 1997, Connecticut Valley was directed by the NHPUC to terminate its purchase of power from the Company. 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 the notice of cancellation of that rate schedule (contingent upon the recovery of the stranded costs that would result from the cancellation of that rate schedule). In December 1997, the FERC rejected the Company's proposal to recover stranded costs through the imposition of a surcharge in the Company's transmission tariff, but indicated that it would consider an exit fee mechanism in the wholesale rate schedule for collecting stranded costs. The FERC denied the Company's motion for a rehearing regarding the transmission surcharge proposal. However, the Company filed a request with the FERC for an exit fee mechanism in the wholesale rate schedule to collect the stranded costs resulting from the cancellation of the wholesale rate schedule. The stranded cost obligation sought to be recovered was $90.6 million in nominal dollars and $44.9 million on a net present value basis as of December 31, 1997.

     On April 24, 2001, a FERC Administrative Law Judge ("ALJ") issued an Initial Decision in the Company's stranded cost/exit fee proceeding. The ALJ ruled that if Connecticut Valley terminates its relationship as a wholesale customer of the Company and subsequently becomes a wholesale transmission customer of the Company, Connecticut Valley shall be liable for payment of stranded costs to the Company. The ALJ calculated, on an illustrative pro-forma basis, a nominal stranded cost obligation of nearly $83.0 million through 2016. The amount of the exit fee as determined by the ALJ will decrease with each year that service continues and normal tariff revenues are collected, and will ultimately be calculated from the date of termination, if notice of termination is ever given. Absent termination of the wholesale rate schedule by mutual agreement, the earliest termination date that could presently occur pursuant to the wholesale rate schedule is December 31, 2003. The stranded c ost obligation as of December 31, 2003, expressed on a net present value basis set forth in the ALJ order, is approximately $33.9 million.

     The ALJ's Initial Decision is subject to review and approval by the FERC. If the Company is unable to obtain approval by the FERC, and if Connecticut Valley is forced to terminate its relationship as a wholesale customer of the Company, it is possible that the Company would be required to recognize a pre-tax loss under this contract totaling approximately $32.9 million as of December 31, 2003. The Company would also be required to write off approximately $0.9 million (pre-tax) of regulatory assets associated with its wholesale business as of December 31, 2003. If the Company obtains a FERC order authorizing the updated requested exit fee and notice of termination is given, Connecticut Valley will apply to the NHPUC to increase rates in order to pay the exit fee. The Company believes that the NHPUC must permit Connecticut Valley to raise rates to recover the cost of the exit fee. However, if Connecticut Valley is unable to recover its costs in rates, Connecticut Valley w ould be required to recognize the loss discussed above.

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      An adverse resolution of the FERC and New Hampshire 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.

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 2,505,658 mWh for the year ended December 31, 2001. The maximum one-hour integrated demand during that period was 411.5 mW, which occurred on August 9, 2001. The Company's and Connecticut Valley's total energy generation and purchased power in 2001, including that related to all resale customers, was 3,104,465 mWh.

     The following table shows the sources of such energy and capacity available to the Company and Connecticut Valley for the year ended December 31, 2001. For additional information related to purchased power costs, refer to PART II Item 7, herein.

	Year Ended December 31, 2001
	Net Effective    Capability    12 Month     Average	Generated          and Purchased
	MW	mWh	%
Wholly-Owned Plants
Hydro	26.7	126,485	4.1
Diesel and Gas Turbine	26.9	3,021	0.1
Jointly-Owned Plants
Millstone #3	20.0	141,261	4.6
Wyman #4	11.0	10,812	0.4
McNeil	10.5	38,443	1.2
Equity Ownership Plants
Vermont Yankee	163.0	1,298,928	41.8
Major Long Term Purchases
Hydro-Quebec	142.8	1,086,667	35.0
Other Purchases
System and other purchases	99.3	105,306	3.4
Independent power producers	31.2	168,382	5.4
Unit purchases	0.0	45,964	1.5
Entitlement purchases	0.0	10,762	0.3
NEPOOL (ISO-New England)	0.0	68,434	2.2
Total	531.4	3,104,465	100.0

Wholly Owned Plants

     The Company owns and operates 20 hydroelectric generating facilities in Vermont which have an aggregate nameplate capability of 44.7 mW and two gas-fired and one diesel-peaking unit with a combined nameplate capability of 28.9 mW.

Jointly Owned Plants

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

Name	Location	Fuel Type	Ownership	mW Entitlement	Net Generation mWh	2001 Load Factor	Net Plant    Investment
Millstone Unit #3	Waterford, CT	Nuclear	1.73%	20.0	141,261	80.6%	$46,523,854
Wyman #4	Yarmouth, ME	Oil	1.78%	11.0	10,812	11.2%	$  1,100,965
Joseph C. McNeil	Burlington, VT	Various	20.00%	10.6	38,443	41.4%	$  6,470,856
Highgate Transmission Facility	Highgate Springs, VT		47.35%	N/A	N/A	N/A	$  7,796,149

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     The Company receives its share of the output and capacity of Millstone Unit #3, a 1,159 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 Converter, a 225 mW facility is directly connected to the Hydro-Quebec System to the north of the Converter and to the VELCO System for delivery of power to Vermont Utilities. This facility can deliver power in 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 in 2001 resold at cost 3.9% of its entitlement. The Company's equity ownership and net entitlement were 31.3% and 31.1%, respectively, as of December 31, 2001.

     On January 16, 2002, Vermont Yankee announced that it had reached an agreement with the secondary purchasers and had purchased back the shares held by the minority stockholders. As a result, the Company's equity ownership and net entitlement changed in the first quarter of 2002 to 33.23% and 34.8%, 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 163 mW was the Company's net entitlement at December 31, 2001. Vermont Yankee's plant performance for the past five years is shown below:

	Availability Factor (See Note 1)	Capacity Factor (See Note 2)
1997	95.4	93.3
1998	75.2	73.5
1999	90.9	88.8
2000	99.5	99.2
2001	93.0	91.2

     Vermont Yankee was shut down for scheduled refueling outages in 1998, 1999 and 2001. The next scheduled refueling outage is October 2002. The Vermont Yankee plant currently has several fuel rods that will require repair during 2002, a maintenance requirement that is not unique to Vermont Yankee. There are various means of addressing the maintenance, including a temporary shutdown of the plant, or a delay in shutdown accompanied by a reduction in the generation output at the plant. At the present time, the Company is unable to estimate when the maintenance will occur or its ultimate cost, but it could be material.

Notes:

1. "Availability Factor" means the hours that the plant is capable of producing electricity
   divided by the total hours in the period.
2. "Capacity Factor" means the total net electrical generation divided by the product of the
   maximum design electrical rating capacity of 514 mW through April 30, 1995 and 522 mW effective
   May 1, 1995, multiplied by the total hours in the period.

     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. 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, refer to PART II Item 8, Note 2 herein.

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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 include charges for decommissioning costs in the cost of capacity, as approved by the FERC.

     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, Note 2, for information regarding the premature shutdown of the Maine Yankee, Connecticut Yankee and Yankee Atomic nuclear power plants. The Company's obligations for decommissioning costs for Vermont Yankee, Maine Yankee, Connecticut Yankee, Yankee Atomic and Millstone Unit #3 are described below.

Vermont Yankee  Vermont Yankee's current decommissioning cost study is based on a 1994 site study stated in 1993 dollars. The FERC-approved settlement agreement allowed $312.7 million as the estimated decommissioning cost. Based on the study's assumed cost escalation rate of 4.25% per annum and an expiration of the plant's operating license in the year 2012, the estimated current cost of decommissioning is $471.1 million at the end of 2001 and, at the end of 2012, is approximately $721.8 million. At December 31, 2001, the market value of the Vermont Yankee Decommissioning Trust Fund was approximately $297.1 million. Based on the total estimated costs to decommission the plant in 2012, the Company's decommissioning obligation is approximately $148.6 million, which represents the value of payments and accrued earnings in the decommissioning trust fund to accomplish the level of funding required at 2012.

     Under the FERC-approved settlement agreement, Vermont Yankee was required to file with the 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. If the plant is not sold, Vermont Yankee will need to submit a new decommissioning filing to the FERC. The sale of the plant would transfer responsibility for decommissioning the plant to the new owner and make a revised schedule of decommissioning unnecessary.

     On February 14, 2001, the PSB issued its Order Dismissing Petition in Docket No. 6300, the proceeding in which the Company, along with Green Mountain Power ("GMP"), Vermont Yankee and AmerGen Energy Company ("AmerGen") sought PSB approval of the sale of the Vermont Yankee nuclear plant to AmerGen. In this Order, the PSB determined that the proposed purchase price, as filed in November 2000, pursuant to a Memorandum of Understanding, did not reflect the fair market value of the plant and, therefore, the sale did not promote the general good of the State of Vermont. This ruling was consistent with the Company's position. The PSB dismissed the petition for approval in March 2001. The management of Vermont Yankee subsequently concluded that selling the plant at auction would provide the greatest benefit to the owners and consumers. The investment banking firm of JPMorgan was retained by Vermont Yankee as the exclusive financial advisor for the auction.

     As a result of issues raised related to the cancelled AmerGen sale, Vermont Yankee reached an agreement in principle with the Vermont Yankee sponsors and their secondary power purchasers, the DPS and the FERC staff that reduces the Vermont Yankee cost of service the sponsors and the secondary purchasers will expect to pay through 2012. The agreement is reflected in billings to sponsors and secondary purchasers effective July 2001. The FERC approved the agreement on September 13, 2001.

     On August 15, 2001, Vermont Yankee announced that a sales agreement had been reached with Entergy Corporation ("Entergy") for $180 million, representing $145 million for the plant and related assets and $35 million for nuclear fuel. Entergy will also assume decommissioning liability for the plant and its decommissioning trust fund. The agreement includes a purchase power contract with prices that generally range from 3.9 cents to 4.5 cents per kilowatt-hour subject to a "low-market adjuster" that protects the current Vermont Yankee owner-utilities, including the Company and its power consumers, in the event power market prices drop significantly. On September 27, 2001, the Company filed testimony with the PSB in support of the sale. In an order entered October 26, 2001, the PSB granted intervention to several parties that the Company did not oppose, and established a schedule that provides for discovery, hearings and final briefing by April 29, 2002. Certain of the inter venors were secondary purchasers of Vermont Yankee power, which were seeking adjustments in their power purchase contracts, and stockholders of Vermont Yankee, which were asserting dissenters' rights. On January 16, 2002, Vermont Yankee announced that it had reached an agreement with the secondary purchasers and had purchased back the shares held by the minority stockholders; these parties have requested to withdraw from the PSB proceeding.

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     On January 7, 2002, the DPS and the remaining intervenors prefiled their direct testimony in the PSB proceeding. Initial hearings occurred during the first week of February 2002 with prefiled rebuttal testimony due on February 25, 2002, and rebuttal hearings March 18 through March 22, 2002. On March 5, 2002, the DPS, Vermont Yankee, Entergy, GMP and the Company filed a Memorandum of Understanding resolving all issues among these parties. A schedule has been set in the PSB proceeding which contemplates a closing, if the sale is approved, by the end of July 2002. The Company cannot predict the outcome of the proceedings.

     The sale is also subject to other regulatory approvals including the Nuclear Regulatory Commission and the Securities and Exchange Commission.

Maine Yankee Maine Yankee's total estimated decommissioning costs, based on a 1998 study, amounts to approximately $536.0 million in 1998 dollars. In January 2002, Maine Yankee and Federal Insurance agreed on a settlement of the pending litigation arising from contractor performance when the original contractor, Stone and Webster, went into bankruptcy. A settlement payment of $44.0 million has been deposited into the Maine Yankee

Decommissioning Trust Fund. Future payments for the closing, decommissioning and recovery of the remaining investment in Maine Yankee, including the insurance settlement, are currently estimated to be approximately $494.2 million; the Company's share is expected to be approximately $9.9 million to be paid over the period 2002 through 2008.

Connecticut Yankee Connecticut Yankee's estimated decommissioning costs, based on a July 2000 settlement with the FERC and the intervenors, amounts to approximately $569.0 million in January 2000 dollars. The settlement rates became effective September 1, 2000, following the FERC order of July 26, 2000. Future payments for the closing, decommissioning and recovery of the remaining investment in Connecticut Yankee are currently estimated to be approximately $226.6 million; the Company's share is expected to be approximately $4.5 million to be paid over the period 2002 through 2007.

Yankee Atomic As of July 2000, Yankee Atomic had collected from its sponsors sufficient funds, based on a current forecast, to complete the decommissioning effort and to recover all other FERC-approved costs of service. Therefore, Yankee Atomic discontinued billings to its sponsors pending the need to increase or decrease the funds available for the completion of its financial obligations, including decommissioning. Such a change would require a FERC review and approval.

Millstone Unit #3 The Company remained an owner of the Millstone Unit #3 facility when Dominion Nuclear Connecticut ("DNC") became the lead owner with approximately 93.47% of the plant joint-ownership. As part of the regulatory approvals of the Sales to DNC by the joint owners of that plant, DNC has represented to the Nuclear Regulatory Commission ("NRC") and other regulatory bodies, including the Connecticut Department of Public Utility Control, that the Millstone Unit #3 Decommissioning Trust Fund, for its share of the plant, exceeds the NRC minimum calculation required and therefore no further contributions to the fund are required at this time. The Company has agreed with the DPS position in its recent rate case that the DNC representation that contributions currently can cease is appropriate subject to periodic review of both the fund balance and the NRC minimum calculation upon which the DNC bases its assertion of fund adequacy. The Company could choose to renew funding at its own discreti on as long as the minimum requirement is met or exceeded.

Vermont Yankee - Nuclear Fuel

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 re-negotiation of existing contracts routinely occurs, often focusing on one of the four components at a time. The cost of the 2001 reload was approximately $16.0 million, and the cost of the 2002 reload is estimated to be approximately $23.0 million. Future refueling costs will depend on market and contract prices.

Low-Level Waste In 1998, the United States Congress approved the tri-state compact between Vermont, Texas and Maine to site a facility in Texas for the disposal of low-level radioactive waste. Also in 1998, the proposed Texas low-level waste disposal site in Hudspeth County was rejected because of geological and socioeconomic concerns. Various parties have proposed alternative sites in Texas. Because of delays in the ratification and siting processes, Vermont Yankee cannot predict when a facility in Texas will be licensed and built. However, it is unlikely that waste disposal under the compact will begin prior to 2003. Vermont Yankee has been disposing of low-level waste

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at other active sites and currently has the capacity to store all of its low-level waste on site until the year 2007. If the Texas facility is not available by that date, Vermont Yankee will continue to pursue other options.

     Under the terms of the compact and related Vermont Statutes, Vermont will pay Texas, and in turn assess in-state generators of low-level waste up to $27.5 million to site, license and construct the disposal facility. The Governors of the three States participating in the compact have agreed that any required payment under the compact will be deferred until a site is selected and a facility is licensed. Vermont Yankee has received FERC approval to recover the cost of this compact from Sponsors over the remaining life of the plant, commencing with the first payment to Texas.

Spent Fuel Disposal 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. 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, although the DOE has stated that the earliest would be 2010. These delays by the DOE have caused Vermont Yankee to consider other costly alternatives for storing high-level waste.

     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 2008 refueling outage. Vermont Yankee is also investigating other options for additional storage capacity beyond the year 2008.

     Various legal proceedings have been filed by the owners and operators of nuclear power plants and by states and state regulatory agencies against the DOE and the federal government to enforce the DOE's obligation to dispose of spent nuclear fuel and are seeking damages resulting from the DOE's breach of those obligations. In addition, legislation has been introduced in Congress in the past several years to assure that the DOE carries out its obligations and to protect the funds paid to the government by utilities and their customers that were intended to pay for the disposal of utilities' spent nuclear fuel.

     In July 1996, the United States Court of Appeals for the District of Columbia Circuit ruled that the DOE had an unconditional obligation to begin disposing of the utilities' spent nuclear fuel by January 31, 1998, and that the absence of an interim storage facility did not excuse the DOE from that obligation. In November 1997, the same Court in ruling on a petition brought by 36 utilities, including Vermont Yankee, reaffirmed the 1996 ruling but declined to order the DOE to accept spent nuclear fuel, saying that the utilities had another potentially adequate remedy under the DOE contract.

     After the January 1998 deadline passed without compliance by the DOE with its contractual and statutory obligation, 41 utilities, including Vermont Yankee, and 60 states and state regulatory commissions, petitioned the same Court to compel the DOE to act. In orders issued in May 1998 and July 1998, the Court declined to order the DOE to act and again directed the utilities to pursue relief in accordance with their DOE contracts. In November 1998, the United States Supreme Court denied petitions by the Government and by the states and state agencies to review the lower Court's decisions.

     Beginning in February 1998, a series of lawsuits have been filed with the United States Court of Federal Claims seeking damages from the Government for the DOE's breach of its obligation to begin disposing of the utilities' spent fuel by the 1998 deadline. In October and November 1998, the Court granted a summary judgement in favor of Yankee Atomic Electric Company, Connecticut Yankee Power Company and Maine Yankee Atomic Power Company (collectively "Yankee") as to the DOE's liability for its breach of the 1998 obligation. The Court rejected the Government's argument that the utilities must first bring claims for damages to the DOE Contracting Officer. In April 1999, another judge of the United States Court of Federal Claims, in a case brought by Northern States Power Company, reached the opposite conclusion, ruling that the utility could not sue for breach of contract damages in the Court but must rather submit a claim for equitable adjustment with the DOE Contracting Off icer.

     On August 31, 2000, the United States Court of Appeals for the Federal Circuit decided appeals from both Yankee and Northern States cases, ruling that the utilities were entitled to sue in the United States Court of Federal Claims for breach of contract damages and need not first submit equitable adjustment claims to the DOE Contracting Officer. In all the cases, the Government has filed motions for partial summary judgement regarding

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the rate of spent fuel acceptance and on the issue of Greater Than Class C Radioactive Waste. The Government has also filed motions to dismiss takings and illegal exaction claims in those cases, which include such claims. In the Yankee cases, the Government was obligated to submit its pretrial filings by February 8, 2002, which has been postponed. The Yankee plaintiffs submitted their pretrial filings in June 1999.

     On July 19, 2000, the DOE entered into a settlement agreement with PECO Energy Company ("PECO") allowing PECO to take credits against payments into the Nuclear Waste Fund to offset certain spent fuel storage costs which PECO had incurred because of the DOE's failure to meet its 1998 obligation. Alabama Power Company and a number of other utilities have initiated a challenge in the United States Court of Appeals for the Eleventh Circuit to the DOE's attempt to use Nuclear Fuel Waste Fund credits to offset potential spent fuel damages claims.

     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 Vermont Yankee 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 2000, Vermont Yankee accumulated $116.5 million in an irrevocable trust to be used exclusively for defeasing this obligation ($120.1 million including accrued interest) at some future date, provided the DOE complies with the terms of the aforementioned co ntract.

Nuclear Liability and Insurance

     The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $9.5 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 $9.3 billion per incident by assessing $88.1 million against each of the 106 reactor units that are currently subject to the Program in the United States, limited to a maximum assessment of $10.0 million per incident per nuclear unit in any one year. The maximum assessment is adjusted at least every five years to reflect inflationary changes. The Price-Andersen Act has been renewed three times since it was first enacted in 1957. The Act is set to expire in August 2002 and Congress is currently considering reauthoriz ation of this legislation. 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 - Hydro-Quebec

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

     The average annual amount of capacity that the Company will purchase from January 1, 2002 through October 31, 2012 is 143 mW, with lesser amounts purchased through October 31, 2016. The Company's total commitment to purchase power under these contracts on a nominal basis is approximately $877 million over the contract term. In February 1996, the Company reached an agreement with Hydro-Quebec that lowered the 1997 cost of power by $5.8 million. As part of this agreement, the Company made 54 mW of Phase I/II capacity available to Hydro-Quebec for its use to deliver an existing Firm Energy Contract or jointly marketed energy contracts to buyers in NEPOOL during the period from July 1, 1996 through June 30, 2001.

     In the early phase of the VJO Power 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 through 1996. In 1994, the Company negotiated a third sellback arrangement whereby the Company received 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 upon four year's written notice, to reduce capacity deliveries by up to 50 mW beginning as early as 2007 until 2015. This option includes the use of a like amount of the Company's Phase I/II facility rights. Hydro-Quebec also can exercise an option, upon one year's written notice, to curtail energy deliveries from an annual load factor of 75% to 50% due to adverse hydraulic conditions in Quebec. This can be exercised five times between November 200 0 and October 2015. Additionally, the VJO can elect to change the annual load factor from 75% to between 70% and 80% five times through 2020, while Hydro-Quebec can elect to reduce the load factor to not less than 65% three times during the same period of time (the VJO contract runs through 2020, however, the Company's schedules related to the

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contract end in 2016). The VJO has made three out of five elections to date, while Hydro-Quebec made its first election for the contract year beginning November 1, 2001 and the VJO has since elected to push the start of the 65% load factor to November 1, 2002. The Company does not expect this change in load factor to have a significant financial impact.

     There are specific contractual 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, 2001, the Company's obligation is approximately 46% of the total VJO Power Contract through 2016. The projected total VJO contract obligation on a nominal basis over the term of the contract (2020) is approximately $1.9 billion.

     During January 1998, a significant ice storm affected parts of New York, New England and the Province of Quebec, Canada, resulting in a 61-day interruption of a significant portion of scheduled contractual energy deliveries into Vermont. As a result of the outage, the VJO initiated an arbitration proceeding, in which, the VJO was 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.

     On April 17, 2001, the Company received a decision in the arbitration proceeding which stated that the long-term power supply contract between Hydro-Quebec and the Vermont utilities remains in effect, that Hydro-Quebec is required to reimburse the Vermont utilities for capacity payments made during the outage for power not delivered and ordered a refund to the VJO, valued at up to approximately $20.0 million plus interest, which amount would be adjusted downward to reflect either actual deliveries by Hydro-Quebec in the first quarter of 1998 or an agreement by the parties.

     On July 19, 2001, Hydro-Quebec and the VJO agreed to a final settlement of the arbitration issues. Under the settlement, the VJO will continue to receive power and energy from Hydro-Quebec under this contract through 2016. As part of the settlement, Hydro-Quebec made a $9.0 million payment to the VJO in July 2001, of which the Company's share was approximately $4.3 million. In the third quarter of 2001, the Company applied approximately $2.7 million to the remaining balance of the deferred costs related to the ice storm arbitration. On October 30, 2001, the Company filed a letter with the PSB summarizing its agreement with the DPS on application of the remaining $1.6 million of the Hydro-Quebec settlement to remaining regulatory assets, which agreement is subject to approval by the PSB. See PART II Item 8, Note 13 for additional information regarding the ice-storm arbitration.

Other Purchases

Cogeneration/Independent Power Qualifying Facilities A number of independent producers using hydroelectric, biomass, and refuse-burning generation are currently producing energy, which is purchased by the Company. The majority of the energy is purchased by a state-appointed purchasing agent who purchases and redistributes the power to all Vermont utilities, for the benefit of customers. For the year ended December 31, 2001, the Company and Connecticut Valley received 168,382 mWh from these sources for which it paid $17,242,096. See Part II Item 8, Note 13 for additional information related to Independent Power Producers.

NEPOOL and ISO-New England The Company, represented by 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 engaged or proposing to engage in the wholesale or retail electric power business in New England. NEPOOL continues to exist as the entity representing not only traditional electric utilities but companies that participate in the emerging competitive wholesale electricity marketplace. A new not-for-profit organization, ISO-New England, was established in July 1997, following FERC approval, and immediately assumed responsibility for the management of the New England region's power grid and transmission systems and administering the region's open access tariff. ISO-New England was formed by transferring staff and equipment from NEPOOL to the new organization. ISO-New Englan d has a service contract with NEPOOL to operate the bulk power system and to administer the wholesale marketplace.

     ISO-New England is governed by the FERC, including the principles put forth in FERC Order No. 888, under rules defined by NEPOOL and approved by FERC. They include, providing independent, open and fair access to the regional transmission system, establishing a non-discriminatory governance structure, facilitating market-based wholesale electric transactions, and ensuring the efficient management and reliable operation of the regional bulk power system.

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     ISO-New England established a bidding system which forms the basis for the economic dispatch (based on bid prices) of generation products. This system provides a settlement mechanism which prices the residual of a given generation product that is excess to a participant's own needs, and is offered to the ISO-New England wholesale power market. A participant pays the actual costs for its generation products used to serve its load or taken to market. A participant submits a bid for its generation products to ISO-New England, and if the bid is accepted and if the participant supplies residual generation products to the ISO-New England wholesale market, the participant receives the market-clearing price based on the highest bids accepted for the residual product. If a participant needs to purchase generation products from the ISO-New England wholesale market to serve its load, those purchases are made at market-clearing prices.

     ISO-New England also provides the main marketplace for participants to secure open access transmission for transactions delivered on the Pool Transmission Facilities. The Company is currently working with other transmission providers in New England to develop a Regional Transmission Organization, or RTO, in compliance with FERC Order No. 2000. See PART II, Item 7 herein for additional information regarding RTOs.

     NEPOOL's peak for the year occurred on August 9, 2001 and totaled 25,200 mW and the Company's peak demand occurred on the same day and totaled 411.5 mW. The Company had a reserve margin of approximately 11.8%, at the time of this peak.

Bilateral market The bilateral market for power transactions directly between NEPOOL participants continues as an alternative to the ISO-New England wholesale spot market.

Power Resources - Future

     The Company has sufficient or excess energy under contract to supply its current franchise obligations through 2012, with the need to purchase limited amounts of capacity for each year going forward. In addition, the Company continues to be involved with conservation and load management programs as described below. 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.

TRANSMISSION

VELCO

     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. 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.

     VELCO provides transmission services for the State of Vermont, acting by and through the DPS, 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, or 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, or 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 VETCO if certain dividend requirements are not met.

NEPOOL Arrangements

     VELCO is a participant with all of the major electric utilities in New England in the New England Power Pool ("NEPOOL"), acting for itself and as agent for the Company and twenty-one other Vermont utilities, whereby the generating and transmission facilities of all of the participants are coordinated on a New England-wide basis through a central dispatching agency to assure their operation and maintenance in accordance with proper standards of reliability, and to attain the maximum practicable economy for all of the participants through the interchange of economy and emergency power.

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Capitalization

     VELCO has authorized 92,000 shares of Class B common stock, $100 par value, and 125,000 shares of Class C preferred stock, of which 60,000 shares and 100,000 shares, respectively, were outstanding at December 31, 2001. In addition, three issues of First Mortgage Bonds, aggregating $52,928,000 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") were authorized and outstanding at December 31, 2001. The issuance of bonds under the VELCO Indenture is unlimited in amount but is subject to certain restrictions.

Management

     In 1957 VELCO entered into an agreement (the "Three-Party Agreement") whereby the Company and GMP 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.

     The Company and GMP entered into a Three-Party Transmission Agreement, dated November 21, 1969, as amended, in connection with the transfer of entitlements of the output of the Vermont Yankee plant to VELCO. Under this Agreement, as amended, the Company and GMP 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.

VETCO

     In connection with the importing of Canadian power, VELCO 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 lines of New England Electric Transmission Corporation, a subsidiary of National Grid USA, formerly 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, 2001) of capital contributions from VELCO. VETCO also 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 the representative, has entered into a similar agreement w ith 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, 2001 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 4.55% 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, which began operation in November 1990. This service increased the maximum capacity of the Hydro-Quebec 450 kV DC facilities 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 was completed at a cost of approximately $487 million. Und er 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.

Page 16 of 100

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, including unpriced external factors such as emissions and investment risk.

     The Company worked cooperatively with many entities during 1999 to transfer most energy efficiency programs from the utilities to an independent contractor for the State of Vermont. The Vermont Energy Efficiency Utility began operation in January 2000 and the Company, along with other distribution utilities, took on a role of delivering the state-wide programs through February 2000 until the contractor, Efficiency Vermont, took over delivery. The Company has a continuing obligation to provide customer information and referrals, coordination of customer service, power quality, and any other distribution utility functions, which may intersect with energy efficiency utility activities.

     The Company has retained the obligation to deliver demand side management programs targeted at the deferral of transmission and distribution projects, known as Distributed Utility Planning, or DUP. The DUP is designed to ensure that delivery services are provided at least cost and to create the most efficient transmission and distribution system possible. Rules for the DUP are being developed in Docket No. 6290, a collaborative effort by the Vermont utilities and the DPS, and the DPS is scheduled to present recommendations on Planning Guidelines in June 2002.

DIVERSIFICATION

     The Company's wholly owned non-utility subsidiary, Catamount Resources Corporation, was formed for the purpose of holding the Company's subsidiaries that invest in unregulated business opportunities. Catamount Energy Corporation, a subsidiary of Catamount Resources Corporation, invests through its wholly owned subsidiaries in non-regulated energy-supply generation projects in North America and Western Europe. Eversant Corporation, also a subsidiary of Catamount Resources Corporation, invests in unregulated energy and service-related businesses.

EMPLOYEE INFORMATION

     Local Union No. 300, affiliated with the International Brotherhood of Electrical Workers represents operating and maintenance employees of the Company and its wholly owned subsidiary, Connecticut Valley Electric Company. At December 31, 2001 the Company and its wholly owned subsidiaries employed 572 persons, of which 224 are represented by the union. On December 27, 2001, the Company and its employees represented by the union agreed to a new three-year contract, which expires on December 31, 2004. The new contract provided for a net general wage increase of 3.0% effective December 30, 2001, December 29, 2002 and January 4, 2004 and employee contributions for health-care coverage will increase from 7 to 20 percent of the cost.

SEASONAL NATURE OF BUSINESS

     The Company normally 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.

Page 17 of 100

OFFICERS

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

Executive Officers of the Registrant:

Name and Age	Office	Officer Since
Robert H. Young, 54	President and Chief Executive Officer	1987
Kent R. Brown, 56	Senior Vice President - Engineering and Operations	1996
William J. Deehan, 49	Vice President -Transmission and Generation Planning and Regulatory Affairs	1991
Joan F. Gamble, 44	Vice President - Strategic Change and Business Services	1998
John J. Holtman, 45	Vice President and Controller	2000
Joseph M. Kraus, 46	Senior Vice President Customer Service, Secretary, and General Counsel	1987
James J. Moore, Jr., 43	Senior Vice President	2001
Craig A. Parenzan, 45	Senior Vice President - Business Development	2001
Robert E. Rogan, 42	Vice President - Public Affairs	1998

     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 (COO) commencing in 1993 and Director, President and Chief Executive Officer (CEO) commencing in 1995. Mr. Young also serves as President, CEO, and Chair of the following CVPS subsidiaries: Connecticut Valley Electric Company Inc.; CVPSC - East Barnet Hydroelectric, Inc.; CV Realty, Inc.; Catamount Resources Corporation; Eversant Corporation; AgEnergy, Inc.; SmartEnergy Water Heating Services, Inc.; and, Chair of Catamount Energy Corporation. He is also Director of the following CVPS affiliates: Vermont Electric Power Company, Inc., Vermont Yankee Nuclear Power Corporation; Vermont Electric Transmission Company, Inc.; Yankee Atomic Electric Company; and, The Home Service Store, Inc.

     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. Mr. Brown also serves as Senior Vice President - Engineering and Operations of Connecticut Valley Electric Company Inc., a CVPS subsidiary.

     Mr. Deehan joined the Company in 1985. Prior to being elected to his present position in May 2001, he served as Vice President - Regulatory Affairs and Strategic Analysis. He previously served as Assistant Vice President - Rates and Economic Analysis from April 1991 to May 1996. Mr. Deehan also serves as Vice President - Transmission and Generation Planning and Regulatory Affairs of Connecticut Valley Electric Company Inc., a CVPS subsidiary.

     Ms. Gamble joined the Company in 1989. Prior to being elected to her present position in August 2001, she was Director of Marketing Research & Planning from 1989 to 1996; Director of Strategic and Policy Planning from 1996 to September 1997; Director of Human Resources and Strategic Planning from September 1997 to May 1998; and, Assistant Vice President Human Resources and Strategic Planning from May 1998 to May 2000. She previously served as Vice President - Human Resources and Strategic Planning from May 2001 to August 2001. Ms. Gamble also serves as Vice President - Strategic Change and Business Services for the following CVPS subsidiaries: Connecticut Valley Electric Company Inc.; Eversant Corporation; and, Catamount Energy Corporation. She serves as a Director for the following CVPS subsidiaries: Eversant Corporation; AgEnergy, Inc.; and, SmartEnergy Water Heating Services, Inc.

Page 18 of 100

     Mr. Holtman joined the Company in 2000. Prior to joining the Company, from 1994 to 2000 he served as Director-Financial Reporting at GPU, Inc. Mr. Holtman also serves as Vice President and Controller of the following CVPS subsidiaries: C.V. Realty, Inc.; CVPSC - East Barnet Hydroelectric, Inc.; Connecticut Valley Electric Company Inc.; Catamount Resources Corporation; Eversant Corporation; AgEnergy, Inc.; and, SmartEnergy Water Heating Services, Inc.

     Mr. Kraus joined the Company in 1981. Prior to being elected to his present position in May 2001, he served as Vice President, Corporate Secretary, and General Counsel commencing in 1996 and Corporate Secretary and General Counsel commencing in 1994. He previously served as Senior Vice President, Corporate Secretary, and General Counsel from 1999 to May 2001. Mr. Kraus serves as Director, Senior Vice President Customer Service, Secretary, and General Counsel of the following CVPS subsidiaries: CVPSC - East Barnet Hydroelectric, Inc.; CV Realty, Inc.; Catamount Resources Corporation; Eversant Corporation; AgEnergy, Inc. and, SmartEnergy Water Heating Services, Inc. He also serves as Senior Vice President Customer Service, Secretary, and General Counsel for the following CVPS subsidiaries: Connecticut Valley Electric Company Inc. and Catamount Energy Corporation.

     Mr. Moore joined the Company in February 2001 as Senior Vice President. Prior to joining the Company, from 2000 to 2001, he served as Chairman and CEO and from 1994 to 2000, as President and CEO of American National Power (f/Transco Energy Ventures Company). Mr. Moore also serves as President and Chief Executive Officer of Catamount Energy Corporation, a CVPS subsidiary.

     Mr. Parenzan joined the Company in January 2001 as Senior Vice President - Business Development. Prior to joining the Company he served as Vice President of Business Development, Orthovita and Vice President and COO designate, Partisyn from 1998 to January 2001. From 1996 to 1998 he was Director of Corporate Development and Ventures, Intelstat. From 1995 to 1996 he was Partner and Associate Director, Arthur D. Little, Inc. Mr. Parenzan also serves as Senior Vice President - Business Development of the following CVPS subsidiaries: Eversant Corporation; AgEnergy, Inc.; and, SmartEnergy Water Heating Services, Inc.

     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. Mr. Rogan also serves as Vice President - Public Affairs of Connecticut Valley Electric Company Inc., a CVPS subsidiary.

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 the transmission lines of VELCO, NEP and PSNH. The Company owns and operates 23 small generating stations with a total current nameplate capability of 73.6 mW. The Company's joint ownership interests include, a 1.78% interest in an oil generating plant in Maine; a 20% interest in a wood, gas and oil-fired generating plant in Vermont; a 1.73% interest in a nuclear generating plant in Connecticut; and a 47.35% interest in a transmission interconnection facility in Vermont.

     The electric transmission and distribution systems of the Company include about 616 miles of overhead transmission lines, about 7,519 miles of overhead distribution lines and about 305 miles of underground distribution lines, all of which are located in Vermont except for about 22 miles in New Hampshire and about 2 miles in New York.

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

     The electric systems of Connecticut Valley include about 2 miles of transmission lines, about 439 miles of overhead distribution lines and about 13 miles of underground distribution lines.

     All of 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 on either land owned in fee or pursuant to easements, most 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.

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     VELCO VELCO's properties consist of about 483 miles of high voltage overhead transmission lines and associated substations. The lines connect on the west with the lines of Niagara Mohawk Power Corporation at the Vermont-New York state line near Whitehall, New York, and Bennington, Vermont, and with the submarine cable of NYPA near Plattsburgh, New York; on the south and east with the 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 with the transmission line of Hydro-Quebec at the Quebec-Vermont border in the Town of Norton, Vermont; and connecting with the transmission line of New England Electric Transmission Corporation, a subsidiary of National Grid USA,

at the Vermont-New Hampshire border near New England Power Company's Moore hydro-electric generating station.

Item 3.    Legal Proceedings.

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

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

     There were no matters submitted to security holders during the fourth quarter of 2001.

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PART II

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

     (a)   The Company's common stock is listed 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:

	Market Price
	High	Low
2001
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	$ 17.00    19.64    18.99    18.55	$ 11.625    15.25    15.50    16.20
2000
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	$ 11.5625    11.25    13.00    12.4375	$  9.8125   10.125     9.9375     9.75

     (b)  As of December 31, 2001, there were 10,073 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 2000 and 2001.

     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, 2001, the Common Stock Equity of the unconsolidated Company was 51.2% of total capitalization.

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

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Item 6.     Selected Financial Data.
            (Dollars in thousands, except per share amounts)

For the year	2001	2000	1999	1998	1997
Operating revenues	$302,476	$333,926	$419,815	$303,835	$304,732
Net income before extraordinary charge	$2,589	$18,043	$16,584	$3,983	$17,151
Extraordinary charge net of taxes	182	-	-	-	$811
Net income	$2,407	$18,043	$16,584	$3,983	$16,340
Earnings available for common stock	$711	$16,264	$14,722	$2,038	$14,312
Consolidated return on average   common stock equity	0.4%	8.6%	7.9%	1.1%	7.5%
Earnings per basic and diluted share of   common stock before extraordinary charge	$.08	$1.42	$1.28	$.18	$1.32
Earnings per basic and diluted   share of Common stock	$.06	$1.42	$1.28	$.18	$1.25
Cash dividends paid per share of common stock	$.88	$.88	$.88	$.88	$.88
Book value per share of common   stock	$15.81	$16.57	$16.05	$15.63	$16.38
Net cash provided by operating activities	$30,216	$60,867	$31,232	$21,743	$41,974
Dividends paid	$11,433	$11,888	$11,950	$12,006	$12,630
Construction and plant expenditures	$16,553	$14,968	$13,231	$16,046	$13,841
Conservation and load management   expenditures	$504	$1,136	$2,440	$2,208	$1,837
At End of Year
Long-term debt (1)	$159,771	$152,975	$155,251	$90,077	$93,099
Capital lease obligations (1)	$12,897	$13,978	$15,060	$16,141	$17,223
Redeemable preferred stock (1)	$15,000	$16,000	$17,000	$18,000	$19,000
Total capitalization (excluding   current portion of debt)	$379,236	$381,704	$379,386	$311,454	$324,499
Total assets	$521,674	$539,838	$563,959	$530,282	$531,940

     (1) Excluding current portion

Page 22 of 100

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

Forward-Looking Statements Statements contained in this report that are not historical fact (including Management's Discussion and Analysis of Financial Condition and Results of Operations) are forward-looking statements intended to qualify for the safe-harbors from liability established by the Private Securities Reform Act of 1995. Statements made that are not historical facts are forward-looking and, accordingly, involve estimates, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Actual results will depend, among other things, upon the actions of regulators, the outcome of litigation at the Federal Energy Regulatory Commission ("FERC") involving the Company's regulated companies, the performance of the Vermont Yankee nuclear power plant ("Vermont Yankee"), weather conditions, the performance of the Company's unregulated businesses and the state of the economy in the areas served. The Co mpany cannot predict the outcome of any of these matters.

Critical Accounting Policies

     Preparation of the Company's 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. Note 1 to the Consolidated Financial Statements is a summary of the significant accounting policies used in the preparation of the Company's financial statements. The following is a discussion of the most critical accounting policies used by the Company.

Regulation The Company is subject to regulation by the Vermont Public Service Board, the New Hampshire Public Utilities Commission 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 Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation", or SFAS No. 71, for both its regulated service territories and FERC-regulated wholesale businesses. 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 must be able to collect those rates from customers. If rate recovery becomes unlikely or uncertain, whether due to competition or regulatory action, this accounting standard 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 SFA S No. 71, the accounting impact would be an extraordinary non-cash charge to operations of an amount that could be material. 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 future recovery of its regulatory assets in the State of Vermont and the State of New Hampshire for the Company's retail and wholesale businesses are probable.

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, its unregulated investments, 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.

Purchased Power The Company records the annual cost of power obtained under long-term contracts as operating expenses. Since these contracts do not convey to the Company the right to use property, plant or equipment, they are considered executory in nature.

Other Other significant accounting policies include: 1) estimated unbilled revenues recorded at the end of each quarterly accounting period; 2) depreciation based on the straight-line remaining life method; and 3) income taxes recorded in accordance with SFAS No. 109, "Accounting for Income Taxes."

Earnings Overview

     Central Vermont Public Service Corporation's (the "Company") 2001 net income was $2.4 million or $.06 per basic and diluted share of common stock, which equates to a 0.4% consolidated return on average common equity. This compares to net income and earnings per basic and diluted share of common stock of $18.0 million and $1.42 in 2000, and $16.6 million and $1.28 in 1999. The consolidated return on average common equity was 8.6% for 2000 and 7.9% for 1999.

     Excluding all nonrecurring items discussed below, the Company's net income for 2001 was $16.0 million, or $1.24 per basic and diluted share of common stock. This compares to 2000 net income of $13.7 million, or $1.05 per basic and diluted share of common stock, which excludes nonrecurring income related to the favorable Millstone

Page 23 of 100

Unit #3 settlement and the favorable Connecticut Valley Electric Company ("Connecticut Valley") First Circuit Court of Appeals decision.

     The Company's rate case settlement with the Vermont Department of Public Service ("DPS") increased rates 3.95% effective July 1, 2001, and put to rest the issues surrounding the Vermont utilities' power contract with Hydro-Quebec. As a result, the Company was required to take a one-time charge to earnings of $5.3 million after-tax, or $.46 per share, and had a $1.7 million after-tax, or $.15 per share, favorable impact due to the elimination of under-recovery of costs related to the Hydro-Quebec power contract.

     During 2001, the Company's unregulated subsidiary, Catamount Energy Corporation ("Catamount"), recorded fourth quarter after-tax asset impairment charges of $9.8 million, or $.85 per share, related to four of its investments in non-regulated energy generation projects. The impairment charges are the result of writing down two assets held-for-sale to estimated sales value and issues concerning the future viability of two other operating projects. The Company also had a third quarter extraordinary charge of $0.2 million related to Connecticut Valley, which is again subject to cost-based ratemaking. Earnings in 2000 included nonrecurring income related to the favorable Millstone Unit #3 settlement and Connecticut Valley First Circuit Court of Appeals decision, which are described below.

     Other factors affecting 2001 earnings compared to 2000 included: 1) higher retail sales revenue of $1.4 million after-tax, or $.12 per share, resulting from higher average retail rates due to the June 26, 2001 approved rate order, offset by a 1.9% decrease in retail mWh sales; 2) lower other utility revenues of $0.7 million after-tax, or $.06 per share, primarily due to a FERC-ordered refund of transmission costs in the fourth quarter of 2000; 3) lower net power costs of $4.2 million after-tax, or $.37 per share, mostly related to lower Vermont Yankee operating and decommissioning costs; 4) higher operating and other costs of $2.9 million after-tax, or $.25 per share, due to higher service restoration costs related to storm activity in the first quarter of 2001 and higher costs related to employee benefits; and 5) lower net losses at Eversant Corporation ("Eversant," formerly SmartEnergy Services, Inc.) of $0.2 million after-tax, or $.02 per share, related to Eversant's inves tment in Home Service Store, Inc. ("HSS"), offset by higher business development costs and a fourth quarter 2001 accrual for a potential income tax liability.

     Increased 2000 earnings versus 1999 resulted mainly from nonrecurring income related to the favorable Millstone Unit #3 settlement and the favorable Connecticut Valley First Circuit Court of Appeals decision amounting to $3.2 million after-tax, or $.28 per share, and $1.7 million after-tax, or $.14 per share, respectively, and higher utility revenues of $0.8 million after-tax, or $.06 per share, principally due to a FERC-ordered refund of transmission costs from Citizens Utilities. In addition, Connecticut Valley reversals of disallowed power costs previously accrued and expensed in 1999, had a positive impact of $0.6 million after-tax, or $.05 per share, and lower net losses at Eversant had a positive impact of $0.5 million after-tax, or $.05 per share. Lower operating costs of $1.6 million after-tax, or $.13 per share, resulted from lower service restoration costs and lower regulatory costs related to retail rates. This was offset by the negative impact of $2.6 million a fter-tax, or $.23 per share, due to higher accruals in 2000 for the expected under-recovery of power costs on the Hydro-Quebec power contract compared to 1999, higher net power costs of $2.4 million after-tax, or $.22 per share, primarily resulting from accrued installed capability ("ICAP") deficiency charges and increased Hydro-Quebec capacity costs. In addition, lower earnings at Catamount amounted to $1.2 million after-tax, or $.12 per share, mainly related to a write-down of a portion of the Gauley River equity investment, higher net losses from Catamount's investment in Thetford and Catamount's share of costs incurred in connection with its investment in a wind farm project in Germany.

Page 24 of 100

Results of Operations

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

Operating revenues and megawatt-hour ("mWh") sales A summary for 2001, 2000, and 1999 follows:

	mWh Sales				Revenues (000's)
	2001	2000	1999	2001		2000	1999
Residential	952,509	963,615	948,756	$124,844		$124,237	$123,302
Commercial	933,928	933,851	943,141	110,482		106,089	109,440
Industrial	431,371	465,418	442,308	35,888		38,521	36,823
Other retail	6,291	6,280	6,235	1,787		1,779	1,787
Total retail sales	2,324,099	2,369,164	2,340,440	273,001		270,626	271,352
Resale sales:
Firm	1,927	2,830	2,349	139		142	160
Entitlement (1)	165,184	299,326	195,149	7,303		10,763	10,840
Alliance	-	611,225	2,986,682	-		22,192	100,116
Other	406,694	573,055	869,857	16,153		20,534	22,121
Total resale sales	573,805	1,486,436	4,054,037	23,595		53,631	133,237
Other revenues	-	-	-	5,880		9,669	5,191
Total	2,897,904	3,855,600	6,394,477	$302,476		$333,926	$409,780

(1) Effective January 1, 2000, power purchased from Hydro-Quebec was recorded net of Entitlement sales to Hydro-Quebec,              therefore, the 1999 Entitlement sales have been restated for comparison purposes in the table above.

     Year-to-year fluctuations in total retail mWh sales are affected by economic conditions, weather patterns, and customer usage patterns, which are affected by the absolute cost of electricity and its costs relative to other fuel sources. Retail mWh sales for 2001 decreased 45,065 mWh, or 1.9%, while related revenues increased $2.4 million for 2001 compared to 2000. The June 26, 2001 approved rate order, which allowed for a 3.95% increase in retail rates beginning in July 1, 2001, contributed approximately $4.9 million and the favorable impact of customer mix and unit pricing contributed $1.7 million, while the 1.9% decrease in mWh sales resulted in a $4.2 million decrease. The decline in retail sales in 2001 can be attributed to both mild weather patterns and the slowing economy's impact on many of the Company's industrial customers.

     Compared to 1999, retail mWh sales for 2000 increased 28,724 mWh, or 1.2%, and related revenues decreased $0.7 million, or 0.3%. The revenue decrease was primarily attributable to the rate reduction for the funding of the State of Vermont-sponsored Energy Efficiency Utility ("EEU").

     For 2001, Entitlement mWh sales decreased 45% when compared to 2000, due in part to the discontinuance, in October 2001, of a five-year power contract in which the Company sold approximately 15% of its share of Vermont Yankee output at full cost. Additionally, in 2000 and 2001, the Company entered into short-term unit swap transactions where it sold a small portion of its share of Vermont Yankee for an equal share of the output from other nuclear facilities in New England; the offsetting purchases are included in the Purchased Power and Produced Energy (mWh) table below. In 2001, the Vermont Yankee swap transactions of approximately $1.1 million were included in Other, while the swap transactions of approximately $2.2 million in 2000 were included in Entitlement, in the table above.

     For 2000, Entitlement mWh sales increased 53% when compared to 1999. The increase primarily resulted from Vermont Yankee short-term unit swap transactions as described above. In addition, 1999 included a Vermont Yankee refueling outage, while there was no refueling outage in 2000.

     Other resale sales decreased 166,361 mWh, or 29%, in 2001 compared to 2000, primarily due to lower output and purchases from the Company's power resources, which impacts the amount of energy available for resale. Those reductions included the Vermont Yankee and Millstone Unit #3 refueling outages in 2001, lower Hydro-Quebec Firm Energy Contract purchases due to phase out of the contract, and lower hydro production from the Company's owned facilities and fewer hydro purchases due to low rainfall. Offsetting the decrease in Other were Vermont Yankee unit swap transactions, which were included in Other in 2001 and Entitlement in 2000.

     Other resale sales in 2000 decreased 296,802 mWh compared to 1999 and related revenues decreased $1.6 million. These variances reflected current market conditions in Vermont and New England. These sales made on a short-term basis included sales to ISO-New England and other utilities in New England.

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     Alliance resale sales in 2000 and 1999 resulted 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 and Virginia Power agreed to discontinue the Alliance. For 2000, Alliance resale sales decreased 2,375,457 mWh and related revenues decreased $77.9 million compared to 1999. Alliance-related sales ended in December 2000.

     The $3.8 million decrease in Other revenues in 2001 compared to 2000 primarily resulted from nonrecurring income in 2000 with no comparable items in 2001. In 2000, Other revenues included nonrecurring income of $2.6 million for the reversal of the provision for rate refunds due to a favorable First Circuit Court of Appeals decision allowing Connecticut Valley to recover all of its power costs in rates and a $0.8 million FERC-ordered refund of transmission costs from Citizens Utilities. Compared to 1999, Other revenues in 2000 increased $4.5 million partly due to the items explained above.

     The table below summarizes the components of increases or decreases in revenues compared to the prior year (dollars in thousands):

	2001	2000
Revenue increase (decrease) from:
Retail mWh sales	$   (4,239)	$    2,880
Retail rates (unit price)	6,614	(3,606)
Changes in firm resale sales	(3)	(18)
Changes in entitlement sales	(3,460)	(77)
Change in Alliance sales	(22,192)	(77,924)
Changes in other resale sales	(4,381)	(1,587)
Changes in other revenues	(3,789)	4,478
Net decrease over prior year	$(31,450)	$(75,854)

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, including the unit swap transactions and excluding sources related to the Alliance, is shown below:

Sources of Energy	2001	2000	1999
Nuclear generating companies	43%	43%	34%
Canadian imports	35	34	35
Company-owned hydro	4	6	5
Jointly owned units	6	8	6
Independent power producers	6	6	5
Other sources	6	3	15
	100%	100%	100%

     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. Unit #3 is currently operated by Dominion Nuclear Connecticut ("DNC"), a subsidiary of Dominion Resources, Inc., and Connecticut Yankee is operated by Northeast Utilities ("NU"). The Company 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 also owns a 2% and 3.5% equity interest in Maine Yankee and Yankee Atomic, respectively. The Company owns a 31.3% equity interest in Vermont Yankee, of which its ownership percentage changed to 33.23% in the first quarter of 2002 related to the buy-back of shares held by minority owners of the plant, which is explained in more detail below. The Company's entitlement percentage of Vermont Yankee is 35%. In addition, the Company owns 20 hydroelectric generating units with a total nameplate cap ability of 44.7 mW and two gas-fired and one diesel-peaking unit with a combined nameplate capability of 28.9 mW.

     During scheduled nuclear refueling outages, the Company purchases more costly replacement energy from other sources to satisfy energy needs. In accordance with current ratemaking 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 Vermont Yankee and Millstone Unit #3. During 2001, the Company deferred $5.4 million for maintenance costs.

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Millstone Unit #3

     On July 27, 2000, the Company and the other non-operating owners of Unit #3 reached a settlement with NU related to a demand for arbitration filed in 1997 for recovery of costs resulting from the shutdown of Unit #3 in 1996. In August 2000, as a result of the settlement, the Company received a cash settlement of $5.4 million

     On September 15, 1999, NU announced its intent to auction its nuclear generating plants, including Unit #3. On August 7, 2000, the Connecticut Department of Public Utility Control announced that Dominion Resources, Inc. was the successful bidder in the auction. Pursuant to the terms of the August 2000 settlement described above, the Company participated as a potential seller in that auction, however, upon notification of the sales price, the Company declined the purchase offer. The sale to DNC became final on March 31, 2001. Unit #3 continues to be a jointly owned plant, and the Company is one of two minority owners. The total DNC share of Unit #3 is 93.4707%.

     As part of the regulatory approvals of the sales to DNC by the joint owners of that plant, DNC has represented to the Nuclear Regulatory Commission ("NRC") and other regulatory bodies, including the Connecticut Department of Public Utility Control, that the Millstone Unit #3 Decommissioning Trust Fund, for its share of the plant, exceeds the NRC minimum calculation required and therefore no further contributions to the fund are required at this time. The Company has agreed with the DPS position in its recent rate case that the DNC representation that contributions currently can cease is appropriate subject to periodic review of both the fund balance and the NRC minimum calculation upon which the DNC bases its assertion of fund adequacy. The Company could choose to renew funding at its own discretion as long as the minimum requirement is met or exceeded.

Vermont Yankee

     The Vermont Yankee nuclear power plant, which provides more than one-third of the Company's power supply, began a scheduled refueling outage on April 27, 2001, which ended on May 20, 2001, 11 days shorter than budgeted. The previous refueling outage began on October 29, 1999 and the plant returned to service December 2, 1999. The 1998 refueling outage (March 21-June 3) extended 26 days beyond the scheduled 49 days. The next scheduled refueling outage is October 2002.

     The Vermont Yankee plant currently has several fuel rods that will require repair during 2002, a maintenance requirement that is not unique to Vermont Yankee. There are various means of addressing the maintenance, including an estimated ten-day shutdown of the plant, or a delay in shutdown accompanied by a reduction in the generation output at the plant. At the present time, the Company is unable to estimate when the maintenance will occur or its ultimate cost, but it could be material.

     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 ("AmerGen") and on November 17, 1999, Vermont Yankee executed an Asset Purchase Agreement with AmerGen. On November 16, 2000, the owners of Vermont Yankee accepted and submitted to the PSB an improved offer for the sale of the plant to AmerGen.

     On February 14, 2001, the PSB issued its Order Dismissing Petition in Docket No. 6300, the proceeding in which the Company, along with GMP, Vermont Yankee and AmerGen sought PSB approval of the sale of the Vermont Yankee nuclear plant to AmerGen. In this Order, the PSB determined that the proposed purchase price, as filed in November 2000, pursuant to a Memorandum of Understanding, did not reflect the fair market value of the plant and, therefore, the sale did not promote the general good of the State of Vermont. This ruling was consistent with the Company's position. The PSB dismissed the petition for approval in March 2001. The management of Vermont Yankee subsequently concluded that selling the plant at auction would provide the greatest benefit to the owners and consumers. The investment banking firm of JPMorgan was retained by Vermont Yankee as the exclusive financial advisor for the auction.

     As a result of issues raised related to the cancelled AmerGen sale, Vermont Yankee reached an agreement in principle with the Vermont Yankee sponsors and their secondary power purchasers, the DPS and the FERC staff that reduces the Vermont Yankee cost of service the sponsors and the secondary purchasers will expect to pay through 2012. The agreement is reflected in billings to sponsors and secondary purchasers effective July 2001. The FERC approved the agreement on September 13, 2001.

     On August 15, 2001, Vermont Yankee announced that a sales agreement had been reached with Entergy Corporation ("Entergy") for $180 million, representing $145 million for the plant and related assets and $35 million for nuclear fuel. Entergy will also assume decommissioning liability for the plant and its decommissioning trust fund. The agreement includes a purchase power contract with prices that generally range from 3.9 cents to 4.5 cents per kilowatt-hour subject to a "low-market adjuster" that protects the current Vermont Yankee owner-utilities,

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including the Company and its power consumers, in the event power market prices drop significantly. On September 27, 2001, the Company filed testimony with the PSB in support of the sale. In an order entered October 26, 2001, the PSB granted intervention to several parties that the Company did not oppose, and established a schedule that provides for discovery, hearings and final briefing by April 29, 2002. Certain of the intervenors were secondary purchasers of Vermont Yankee power, which were seeking adjustments in their power purchase contracts, and stockholders of Vermont Yankee, which were asserting dissenters' rights. On January 16, 2002, Vermont Yankee announced that it had reached an agreement with the secondary purchasers and had purchased back the shares held by the minority stockholders; these parties have requested to withdraw from the PSB proceeding.

     On January 7, 2002, the DPS and the remaining intervenors prefiled their direct testimony in the PSB proceeding. Initial hearings occurred during the first week of February 2002 with prefiled rebuttal testimony due on February 25, 2002, and rebuttal hearings March 18 through March 22, 2002. The current schedule in the PSB proceeding could permit a closing, if the sale is approved, by the end of July 2002. The Company cannot predict the outcome of the proceedings.

     The sale is also subject to other regulatory approvals including the Nuclear Regulatory Commission and the Securities and Exchange Commission.

Maine Yankee

     On August 6, 1997, the Maine Yankee nuclear power plant was prematurely retired from commercial operation. The Company relied on Maine Yankee for less than 5% of its required system capacity. The decommissioning effort continues per project plans. The total expected decommissioning costs for Maine Yankee are $536.0 million in 1998 dollars. The original decommissioning contractor, Stone and Webster, filed for bankruptcy and, in January 2002, Maine Yankee and Federal Insurance agreed on a settlement of the pending litigation arising from contract performance when Stone and Webster went into bankruptcy. A settlement payment of $44.0 million has been deposited into the Maine Yankee Decommissioning Trust Fund. Future payments for the closing, decommissioning and recovery of the remaining investment in Maine Yankee, including the insurance settlement are currently estimated to be approximately $494.2 million; the Company's share is expected to be approximately $9.9 millio n to be paid over the period 2002 through 2008.

     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, limiting the amounts they will pay for decommissioning the Maine Yankee plant and settling other points of contention affecting individual secondary purchasers.

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% of its required system capacity. Connecticut Yankee continues to decommission the site. Connecticut Yankee reached a settlement with the FERC and the intervenors that allows for the cost recovery of the total expected decommissioning costs now estimated at $569.0 million in January 2000 dollars, as well as other appropriate costs of service. The settlement rates became effective September 1, 2000, following the FERC order of July 26, 2000. Connecticut Yankee is required to commence a new filing before the FERC no later than July 1, 2004 to review the status of decommissioning expenditures, the expected remaining decommissioning costs and their collections, and other appropriate issues. Future payments for the closing, decommissioning and recovery of the remaining investment in Connecticut Yankee are currently estimated to be approximately $226.6 million; the Company's share is expected to be approximately $4.5 million to be paid over the period 2002 through 2007.

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. As of July 2000, Yankee Atomic had collected from its sponsors sufficient funds, based on a current forecast, to complete the decommissioning effort and to recover all other FERC-approved costs of service. Therefore, Yankee Atomic discontinued billings to its sponsors pending the need to increase or decrease the funds available for the completion of its financial obligations, including decommissioning. Such a change would require a FERC review and approval. Yankee Atomic is successfully decommissioning the site as planned.

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Maine Yankee, Connecticut Yankee and Yankee Atomic Decommissioning Costs

     Currently, costs billed to the Company by Maine Yankee and Connecticut Yankee, including a provision for ultimate decommissioning of the units, are being collected from the Company's customers through existing retail and wholesale rate tariffs. As of December 31, 2000, the Company completed its obligation for decommissioning costs based on current estimates related to Yankee Atomic. The Company's share of remaining costs with respect to Maine Yankee and Connecticut Yankee's decisions to discontinue operation were estimated to be $10.6 million and $4.5 million, respectively, at December 31, 2001. These amounts are subject to ongoing review and revisions and are reflected in the accompanying Consolidated Balance Sheet both as regulatory assets and nuclear dismantling liabilities (current and non-current). In the first quarter of 2002, the Company plans to revise its estimates related to Maine Yankee to reflect the impact of the insurance settlement described above.

     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. This would have the effect of lowering costs to customers. 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.

Cogeneration/Independent Power Qualifying Facilities

     The Company purchases power from a number of Independent Power Producers ("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 2001, the Company received 168,382 mWh of which 118,187 mWh is associated with the Vermont Electric Power Producers and 37,293 mWh from a waste-to-energy electric generating facility owned by Wheelabrator Claremont Company, L.P. The Company expects to purchase approximately 197,000 mWh of independent power output in each year 2002 through 2006. 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 $116 million , which excludes the impact of the January 28, 2002 Memorandum of Understanding described below.

     On August 3, 1999, the Company, 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 outlined seven specific elements that, if implemented, would reduce purchase power costs and reform these contracts for the benefit of consumers. On September 3, 1999, the PSB opened a formal investigation in Docket No. 6270 regarding these contracts as requested by the Petition. Shortly thereafter, Citizens Utilities, Hardwick Electric Department and Burlington Electric Department notified the PSB that they were withdrawing from the Petition but would participate in the case as non-moving parties. In a separate action before the Chittenden County Superior Court brought by several IPP owners, GMP's full participation in this PSB proceeding was enjoined and that injunction has since been appealed to and affirmed by the Vermont Supreme Court. The Company, the other moving utilities and the DPS requested that the PSB issue an order requiring GMP's full participation in the PSB proceeding. The PSB declined to rule on the request but retained authority to require GMP to provide specific information or to submit any other specific filing.

     On November 22, 2000, the IPPs filed dispositive motions in Docket No. 6270, urging the PSB to declare that it lacks jurisdiction to grant relief sought by the Company's Petition. On January 8, 2001, the Company and the other petitioning utilities filed responses to the IPPs' motions, supporting the PSB's exercise of jurisdiction, as called under the Petition. The DPS also made a filing in support of jurisdiction. On June 1, 2001, the PSB Hearing Officer issued a Proposal for Decision ("PFD") on the PSB's jurisdiction to consider the Petition. The PFD recommended that the PSB find that it has jurisdiction to consider the relief sought under the Petition but that the PSB may be precluded from issuing orders reducing the lengths of a Purchasing Agent contract or requiring buy-outs or buy-downs. Docket participants filed comments on the PFD. On September 18, 2001, the PSB issued an Order regarding jurisdiction in which it adopted the conclusions of the Hearing Officer's PF D and found that it has jurisdiction to consider five of the seven claims outlined in the original Petition.

     The IPPs 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." By motion filed in the Superior Court in September 2000, the IPPs sought summary judgement in this action. On January 19, 2001, the Washington County Superior Court dismissed the IPPs' action, which the IPPs appealed to the Vermont Supreme Court. The IPPs also asked the Vermont Supreme Court to stay the

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proceeding before the PSB pending the outcome of their appeal. By order dated April 5, 2001, the Vermont Supreme Court denied the IPPs' request for a stay.

     On March 15, 2001, the IPPs also filed a related complaint before the FERC, requesting that the FERC issue an order preventing the Company and the other Vermont utilities from employing FERC Order No. 888 to require the IPPs, either directly or indirectly, to reserve transmission service and pay transmission charges in connection with their power sales. In principal part the IPPs argue that such reservations and related charges are prohibited under the regulations adopted by the State of Vermont to implement the Public Utilities Regulatory Policies Act of 1978. On April 4, 2001, the Company and other Vermont utilities filed their response arguing that the IPP complaint should be dismissed on procedural grounds and opposing the IPPs' allegations on the merits. By Order dated May 16, 2001, the Commission declined to grant the relief requested and instead found that the complaint was premature in light of the fact that the PSB has yet to rule on the disputed issues in the pro ceeding open before it to consider the Petition.

     In September 2001, the Petitioners and the IPPs agreed to enter into a settlement discussion and on September 28, 2001 filed a Stipulation for Stay requesting that further proceedings in the Docket be stayed to provide the parties an opportunity to engage in settlement negotiations. A similar motion was also filed with the Vermont Supreme Court regarding the appeal on the so-called "scrivener's error" case. On October 18, 2001, the PSB Hearing Officer issued an order granting the Stipulation for Stay and indicated that a status conference would be convened midway through the 90-day period, which was due to expire January 4, 2002. A status conference on the parties' settlement efforts was convened on November 27, 2001.

     After several extensions, on January 28, 2002, the Petitioners and the IPPs filed a Memorandum of Understanding with the PSB which, if approved, establishes a comprehensive settlement to the issues in Docket No. 6270. The Memorandum of Understanding would provide:

1. power cost reductions nominally worth approximately $11.0 million to $14.0 million over ten years;
2. the agreement of the IPPs to support efforts before the Vermont General Assembly and the PSB to authorize securitization and to negotiate for the buy-out and buy-down of the IPP contracts with the goal of achieving additional power cost savings; and
3. a global resolution of various related issues.

     At this time, proceedings are continuing in PSB Docket No. 6270 to consider the Memorandum of Understanding. A status conference on the matter was held in February 2002. A decision in this matter is expected in 2002.

Generating Units

     The Company owns and operates 20 hydroelectric generating units, two gas turbines and one diesel peaking unit with a combined nameplate capability of 73.6 mW.

     The Company is currently in the process of relicensing or preparing to relicense eight separate hydroelectric projects under the Federal Power Act. These projects, some of which are grouped together under a single license, represent approximately 29.9 mW, or about 66.8% of the Company's total hydroelectric nameplate capacity. In the new licenses, the FERC is expected to impose conditions designed to address the impact of the projects on fish and other environmental concerns. The Company is unable to predict the specific impact of the imposition of such conditions, but capital expenditures and operating costs are expected to increase in the short term to meet these licensing obligations and net generation from these projects will decrease in future periods.

     Peterson Dam: The Company has worked with environmental groups and the State of Vermont since 1998 to develop a plan to relicense Peterson Dam, a 6.2 mW hydroelectric station on the Lamoille River. The Vermont Natural Resources Council ("VNRC") has proposed removal of the dam, a 1948 hydro-generating unit that produces power to energize approximately 3,000 homes per year.

     In August 2000, talks broke down, and the VNRC called publicly for removal of the dam. The Company has initiated broader discussions with VNRC, Trout Unlimited, the Vermont Agency of Natural Resources and other parties, related to the economic, reliability and environmental issues that Peterson's removal would create.

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 the ISO-New England hourly clearing market to take advantage of immediate pricing and other market conditions. Revenue from sale transactions is used to reduce purchased power costs. Purchases from ISO-New England are included in Other

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sources in the Sources of Energy table above. The Company also engaged in marketing activities with Virginia Power, which jointly supplied wholesale power primarily in the Northeast states, however, in the third quarter of 1999, the Company and Virginia Power agreed to discontinue the Alliance and the remaining committed purchases under the Alliance were fulfilled in 2000. These purchases are excluded from the sources of energy table above.

Net Purchased Power and Production Fuel

     The net cost components of purchased power and production fuel costs, including Alliance purchases, for the past three years were as follows (dollars in thousands):

	2001		2000		1999 (1)
	Units	Amount	Units	Amount	Units	Amount
Purchased and produced:
Capacity (mW)	436	$  86,164	427	$  96,850	545	$  90,879
Energy (mWh)	2,784,443	61,498	3,594,942	89,090	6,208,364	168,546
Total purchased power costs		147,662		185,940		259,425
Production fuel (mWh)   Total purchased power and   production fuel costs	320,022	2,995 150,657	452,387	4,825 190,765	402,355	3,165 262,590
Less entitlement and other resale  sales (mWh)	571,878	23,456	1,483,607	53,489	4,051,688	133,077
Net purchased power and production  fuel costs		$127,201		$137,276		$129,513

      (1) Effective January 1, 2000, power purchased from Hydro-Quebec was recorded net of entitlement sales to Hydro-Quebec,
              therefore, the 1999 Purchased and produced energy and entitlement and other resale sales have been restated for
              comparison purposes in the table above.

     For 2001, purchased capacity costs decreased $10.7 million compared to 2000 primarily related to the following: 1) favorable impact of $5.0 million related to a second quarter 2001 reversal of a $2.5 million power cost accrual in 2000 related to estimated ICAP deficiency charges to ISO-New England due to a December 2000 FERC Order, which was reversed in 2001; 2) the June 26, 2001 rate order that eliminated future disallowances for the under-recovery of Hydro-Quebec power costs resulting in a $2.9 million favorable impact from the reversal of the accrual for estimated under-recovery of Hydro-Quebec power costs in the second quarter of 2001, with no accrual for the future under-recovery of those costs in the third quarter of 2001; and 3) lower Vermont Yankee capacity costs of $3.8 million (including the $5.5 million impact of a net deferral of refueling outage costs) related to lower decommissioning costs beginning July 1, 2001, lower net interest costs and operational efficien cies at the plant.

     Energy costs are directly related to the variable prices of oil and nuclear fuel, but more importantly, to the proportion of the Company's purchased energy that comes from each of these fuel sources. Purchased energy in 2001 decreased $27.6 million compared to 2000, primarily due to Alliance-related purchases of approximately $22.0 million in 2000, which are offset by a decrease in Alliance resale sales. Excluding Alliance-related energy purchases, purchased energy for 2001 decreased $7.6 million compared to 2000 due to a decrease in output by expensive IPP hydro units, decreased balancing purchases from ISO-New England, and a net deferral related to incremental costs of replacement power during nuclear refueling outages.

     In 2001, production fuel costs decreased $1.8 million primarily due to lower output and costs related to the McNeil generating plant, which was operated at a higher capacity level in 2000 to support reliability, and lower output from the Wyman generating station.

     For 2000, purchased capacity costs increased $6.0 million compared to 1999, resulting from the negative impact of net higher loss accruals of $4.6 million in 2000 for expected under-recovery of power costs on the Hydro-Quebec power contract and accrued ICAP deficiency charges in ISO-New England of $2.5 million due to a December 2000 FERC Order which was on appeal. In addition, costs related to the Hydro-Quebec power contract increased by $5.4 million. The increased capacity costs were partially offset by a favorable impact of lower Connecticut Valley loss accruals related to disallowed power costs of $1.2 million, lower Vermont Yankee capacity costs of $2.3 million including the impact of refueling outage deferrals, lower decommissioning costs of $1.0 million, which was primarily related to Yankee Atomic, and lower Alliance-related capacity costs of $1.6 million.

     Energy purchases decreased by $79.4 million for 2000 compared to 1999, primarily from a $76.7 million decrease in Alliance purchases, which are offset by a decrease in Alliance resale sales. Excluding the Alliance,

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energy purchased decreased by $2.7 million for 2000, primarily from a 4.0%, or $5.3 million, decrease in the amount of mWh purchased offset by a 7.5%, or $2.6 million, increase in price.

     In 2000, production fuel costs increased $1.7 million compared to 1999 primarily due to increased operation of the McNeil generating plant to support reliability due to an equipment failure in northern Vermont, and increased fuel costs.

     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 Millstone Unit #3. For additional information see Notes 2 and 13 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 ("FASB") issued a new accounting pronouncement related to asset retirement obligations that includes decommissioning of nuclear power plants. See discussion of Recent Accounting Pronouncements below.

     Based on present commitments and contracts, the Company expects that net purchased power and production fuel costs will be approximately $142.1 million, $139.2 million and $140.7 million for the period 2002 through 2004.

Other operation expenses There was no significant variance related to other operation expenses for 2001 compared to 2000. The decrease of approximately $3.2 million for 2000 versus 1999 resulted primarily from decreased regulatory commission costs related to retail rates as well as decreased conservation and load management costs in 2000, primarily as a result of the EEU.

Maintenance expenses The $3.4 million increase in maintenance expense in 2001 compared to 2000 is primarily due to higher service restoration costs related to storm activity in the first quarter of 2001. The decrease in maintenance expenses of $2.8 million in 2000 versus 1999 is primarily due to lower service restoration costs related to two major storms that occurred in 1999.

Income taxes Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences. Income taxes increased in 2001 compared to 2000 due to changes in permanent differences and an increase in the valuation allowance. For 2000 versus 1999 these taxes decreased as a result of a change in permanent differences for the period.

Other income and deductions Other income and deductions decreased $24.0 million for 2001 compared to 2000 due mainly to the following nonrecurring items: 1) a $9.0 million pre-tax write-off related to the Company's June 2001 approved rate order; 2) $8.9 million of pre-tax asset impairment charges related to Catamount's investments; and 3) a $1.9 million pre-tax write-down of Eversant's investment in HSS. See Diversification below for more detail. Other income and deductions increased for 2000 versus 1999 due to the positive impact of nonrecurring income of $5.4 million related to the favorable Millstone Unit #3 settlement, offset by an increase in the provision for income taxes. The decrease in 1999 was primarily due to lower equity income from Eversant's proportionate share in HSS.

Interest on long-term debt There was no significant variance in interest on long-term debt in 2001 compared to 2000. 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 and 2000. Interest expense reflects the retirement of first mortgage bonds of $4.0 million in 2001, $16.5 million in 2000, and $3.0 million in 1999.

Other interest expense The $0.6 million increase in Other interest expense in 2001 compared to 2000 resulted primarily from a fourth quarter 2001 accrual for interest due on a potential tax liability. Other interest expense decreased for 2000 versus 1999 due to decreases in average outstanding short-term debt.

Extraordinary Charge An Extraordinary charge of $0.2 million resulted from the application of Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation" ("SFAS No. 71"), at Connecticut Valley.

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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 programs. The Company's capital expenditure projections for the years 2002 through 2006 total approximately $ 90.3 million; these projections are revised from time-to-time to reflect changes in conditions. Net cash flow provided by operating activities generated $30.2 million of cash in 2001, $60.9 million of cash in 2000 and $31.2 million in 1999. The $30.7 million decrease in cash from operating activities for 2001 versus 2000 can be attributed to: 1) the scheduled nuclear refueling outages at Vermont Yankee and Millstone Unit #3, in 2001, with no scheduled refueling outages in 2000; 2) the Millstone Unit #3 settlement in 2000; and 3) other changes in working capital.

     The Company ended 2001 with cash and cash equivalents of $45.5 million, a decrease of $2.5 million from the beginning of the year. The decrease in cash for 2001 was the result of $30.2 million provided by operating activities, offset by $30.6 million used for investing activities and $2.1 million used for financing activities.

     Operating Activities Net income and depreciation, including after-tax non-cash items of $16.2 million related to the regulatory asset write-off, Catamount's asset impairment charges and Eversant's investment write-down, provided cash of $35.6 million. Approximately $5.4 million of cash was used for working capital and other operating activities.

     Investing Activities Construction and plant expenditures used cash of approximately $16.6 million and Conservation and Load Management programs used $0.5 million, while $13.7 million was used for non-utility investments mostly related to Catamount's investment in Gauley River. Other investing activities provided $0.2 million.

     Financing Activities Dividends paid on common stock were $10.1 million, while preferred stock dividends were $1.3 million. The pay down of capital lease obligations required $1.1 million, while net long-term debt contributed $9.8 million and sale of common stock from the Company's Treasury shares provided $0.6 million.

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%.

     Based on outstanding debt at December 31, 2001, the aggregate amount of utility long-term debt maturities and sinking fund requirements are $7.0 million, $10.5 million, $75.0 million, $0.0 million and $0.0 million for the years 2002 through 2006, respectively. Substantially all Vermont utility property and plant is subject to liens under the First and Second Mortgage Bonds.

     The Company has an aggregate of $16.9 million of letters of credit that support three series of Industry Development/Pollution Control Bonds, with expiration dates of May 31, 2002. The Company has begun the process of extending these letters of credit to August 31, 2003 with Citizens Bank of Massachusetts. These letters of credit are secured by a first mortgage lien on the same collateral supporting the Company's first mortgage bonds.

     The Company's long-term debt arrangements contain financial and non-financial covenants. At December 31, 2001, the Company was in compliance with all debt covenants related to its various debt agreements.

     Financial obligations of the Company's subsidiaries, discussed below, are non-recourse to the Company. On April 25, 2001, the Company sought and in June 2001 the Company received unanimous approval from its First Mortgage Bondholders to enter into a 42nd Supplemental Indenture to the Company's mortgage dated October 1, 1929 (the "First Mortgage") to exclude its wholly owned non-regulated subsidiary, Catamount Resources Corporation and its subsidiaries (currently Catamount and Eversant), from the term "subsidiary" under the Mortgage. The 42nd Supplemental Indenture (amendment) eliminates the possibility of cross defaults under the First Mortgage occasioned by a default on the indebtedness of Catamount Resources Corporation or its subsidiaries. Additionally, the amendment imposes limitations on the level of the Company's future investment in non-regulated subsidiaries.

Non-Utility

     In 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, of which $21.3 million was outstanding at December 31, 2001. The interest rate is variable, prime-based. Catamount's assets secure the facility. Based on total outstanding debt of $21.5 million at December 31, 2001, the aggregate amount of Catamount's long-term debt maturities are $0.0 million, $3.2 million, $4.2 million, $5.0 million

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and $9.1 million for the years 2002 through 2006, respectively. Catamount's long-term debt contains financial and non-financial covenants. At December 31, 2001, Catamount was in compliance with all covenants under the revolver except that Catamount's capital expenditures exceeded budget by an immaterial amount, which was waived by the lender in February 2002.

     In 1999, SmartEnergy Water Heating Services, Inc. ("SEWHS"), a wholly owned subsidiary of Eversant, secured a $1.5 million, seven-year term loan with Bank of New Hampshire with an outstanding balance of $1.1 million at December 31, 2001. The interest rate is fixed at 9.5% per annum. Based on outstanding debt at December 31, 2001, the aggregate amount of SEWHS's long-term debt maturities are $0.2 million, $0.2 million, $0.2 million, $0.3 million and $0.2 million for the years 2002 through 2006, respectively. SEWHS's long-term debt contains financial and non-financial covenants. At December 31, 2001, SEWHS was in compliance with all debt covenants related to its various debt agreements.

Capital Structure

     The Company's capital ratios (including amounts of long-term debt due within one year) for the past three years were as follows:

	December 31
	2001	2000	1999
Common stock equity	47%	49%	47%
Preferred stock	6	6	6
Long-term debt	43	41	43
Capital lease obligations	4	4	4
	100%	100%	100%

Credit Ratings

     Current credit ratings of the Company's securities by Standard & Poor's and Fitch IBCA ("Fitch") remain as follows:

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

1. Outlook: Stable
2. Outlook: Stable

     On July 11, 2001, Fitch removed the Company from its "Rating Watch Negative" status because of its favorable resolution of the Company's rate order with the PSB.

     On July 17, 2001, Standard & Poor's removed the Company from its "CreditWatch with negative implications" status in response to the PSB's recent rate order, which stabilized the Company's financial position. Standard & Poor's also affirmed its rating of the Company, saying that its outlook on the Company is stable.

     The Company cannot assure that its business will generate sufficient cash flow from operations or that future borrowing 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 through its wholly owned subsidiaries in non-regulated energy-supply generation projects in North America and Western Europe. Through its wholly owned subsidiaries, Catamount has interests in ten operating independent power projects located in Glenns Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont; Thetford,

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England; Hopewell, Virginia; Thuringen, Germany; Mecklenburg-Vorpommern, Germany; Fort Dunlop, England; and Summersville, West Virginia.

     In 2001, Catamount undertook a comprehensive strategic review of its operations. As a result, Catamount has refocused its efforts from being an investor in late-stage renewable energy to being primarily focused on developing, owning and operating wind energy projects. As a result of the change in strategic direction, Catamount is currently pursuing the sale of certain of its interests in non-wind electric generating assets. Depending on prices, capital and other requirements, Catamount will also entertain offers for the purchase of any of its remaining non-wind electric generating assets. Proceeds from the sales will be used to either pay down the outstanding loan balance or be reinvested in the development of new wind projects as well as the acquisition of existing wind projects. Additionally, Catamount is seeking investors and partners to co-invest with Catamount in the development, ownership and acquisition of projects, which will be financed by equity and non-recourse debt. Management cannot predict the timing or outcome of potential future asset sales or whether this new strategy will be successful.

     In November 1999, Catamount partnered with Tyco Capital (formerly CIT Group), a major equipment finance company, and Dana Commercial Credit Corporation ("Dana"), the finance subsidiary of Dana Corporation, to form Catamount Investment Company, LLC ("CIC"), which intended to invest in independent power projects in North America. CIC Luxembourg SarL ("CIC Luxembourg") was also established by the parties mentioned above to invest in independent power projects in Western Europe. CIC Luxembourg participated in two German projects. Tyco Capital, Dana and Catamount decided to dissolve CIC effective December 31, 2001. Catamount recorded a nominal charge to earnings associated with the dissolution of CIC.

     Catamount has projects under development in the United States and Western Europe. In June 2001, Catamount established Catamount Development GmbH, a German corporate entity, 100% owned by Catamount Heartlands Corp., a wholly owned subsidiary of Catamount. The company was formed to hold Catamount's interests in German "greenfield" development by Catamount or projects, which would be purchased by Catamount in mid- to late-stage development.

     Summersville Hydroelectric Power Station, owned by Gauley River Power Partners, L.P. ("Gauley River"), which was still under construction in the first half of 2001, began commercial operation on July 30, 2001. The project experienced construction delays and Gauley River incurred a $0.6 million liquidated liability to its primary purchased power contract holder during July 2001, as a result of power production delays. In November 2001, Catamount and Gauley River signed an agreement to settle the construction dispute related to the cost overruns with the contractor, Black & Veatch Construction, Inc. ("Black & Veatch"), which was approved by the lenders. Under the terms of the agreement, Catamount and Gauley River have agreed to pay Black & Veatch a total of $6.8 million. This amount represents $5.0 million as final settlement on the construction overruns and $1.8 million related to the release of retainage upon completion of certain constr uction items outlined in the agreement. Of the $6.8 million, $5.8 million was paid in the fourth quarter 2001 and the remaining $1.0 million will be paid in the first quarter 2002.

     At December 31, 2001, Gauley River was classified as held-for-sale and the project interests are being actively marketed for sale by Catamount. In the fourth quarter, in accordance with SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" ("SFAS No. 121"), Catamount recorded an after-tax impairment charge to earnings of $1.4 million associated with its interests in Gauley River. The impairment was based on bids received from third parties, less estimated costs to sell. In late December 2001, Catamount issued requests for bids to several parties interested in Gauley River and, in February 2002, entered into an exclusive agreement for the sale of the project.

     Although Catamount has a controlling interest in Gauley River, this investment has not been consolidated in the accompanying financial statements since it is Management's intent to sell this project and therefore control is considered temporary. For equity accounting purposes, the Gauley River investment is treated as 100% ownership.

     Catamount's Fibrothetford Limited ("Fibrothetford") equity investment has been reduced to zero as a result of losses incurred to date. As of July 1, 2001, losses were being applied to Catamount's note receivable balance. Catamount will also reserve against future interest income on the note receivable, which is expected to be approximately $1.3 million over the next twelve months. Fibrothetford received a deferment of the senior debt principal payment due September 30, 2001, avoiding a potential default. That deferred payment was made at the end of October 2001. Fibrothetford is negotiating a refinancing of its debt with a large commercial bank and its owners; Management, however, cannot predict whether Fibrothetford will ultimately be able to restructure its debt and continue as a going concern. At year end, Catamount's Fibrothetford investment was classified as held-for-sale. In the fourth quarter, in accordance with SFAS No. 121, Catamount recorded an after-tax imp airment charge to

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earnings of $3.2 million. Also, a valuation allowance for the $2.2 million deferred tax asset was recorded. The impairment charge was based on review of expected future cash flows and expected market value of Catamount's interest given the project's current financial condition.

     In the fourth quarter 2001, Catamount recorded impairment charges for all of its interests in the Glenns Ferry and Rupert projects for a total after-tax charge of $3.0 million. The impairment charges were the result of the deteriorating financial condition of the projects' steam hosts that are essential to the projects' Qualifying Facility status and long-term viability. The steam hosts are actively seeking resolution of their current financial issues, however, Management cannot predict whether they will ultimately be successful.

     Catamount's after-tax loss for 2001 was $8.7 million and its after-tax earnings were $0.7 million and $2.1 million for 2000 and 1999, respectively.

     Eversant, also a subsidiary of Catamount Resources Corporation, invests in unregulated energy and service-related businesses. Eversant had a 13.4% ownership interest, on a fully diluted basis, in HSS as of December 31, 2001. HSS establishes a network of affiliate contractors who perform home maintenance repair and improvements via membership. HSS began operations in 1999 and is subject to risks and challenges similar to a company in the early stage of development. HSS launched a Commercial Services division in 2001, which meets the needs of small businesses, building owners and property managers. In May 2001, Eversant entered into a convertible loan agreement with HSS and Jupiter Capital ("Jupiter"). Under the agreement, Eversant loaned HSS $2.0 million and Jupiter loaned HSS $5.0 million, which, along with current debt balances and accrued interest, was converted to preferred securities when HSS received an additional cash investment from Jupiter in August 2001. I n September 2001, Eversant recorded a $1.2 million after-tax write-down of its investment in HSS to fair market value. Eversant has previously recorded losses of $9.0 million related to its investment in HSS. At year end, Jupiter committed, based upon continued satisfactory operating progress, to provide an additional $5.0 million in funding to the business over time. The first $1.0 million was invested in December 2001 and Jupiter received options to acquire up to an aggregate of $4.0 million in preferred securities. In January 2002, Jupiter invested an additional $1.0 million and predicts that an additional $2.0-$3.0 million in funding above the $5.0 million may be required and they are currently talking to other parties about providing this capital. Eversant's fully diluted ownership position after the $5.0 million Jupiter investment would be 12.6%.

     In February 2002, HSS announced that Michael Froning, formerly President of the Southern Division of Circuit City Stores, will become President and Chief Executive Officer.

     Eversant's share of the HSS losses for 2001 was zero as the Company's equity investment was reduced to zero as a result of losses incurred to date. As of December 31, 2001, Eversant has a preferred equity investment in HSS of $1.4 million, recorded at estimated fair value.

     During 2001, AgEnergy (formerly SmartEnergy Control Systems), a wholly owned subsidiary of Eversant, filed a claim in arbitration against Westfalia-Surge, the exclusive distributor that markets and sells its SmartDrive Control product. The arbitration concerned the Company's claim that Westfalia-Surge had not conducted itself in accordance with the exclusive distributorship agreement between the parties. On January 28, 2002, the Company received an adverse decision related to the arbitration proceeding with Westfalia-Surge. The Company does not expect a material liability related to the decision and is currently in discussions with Westfalia-Surge regarding this matter. The SmartDrive Control product has generated approximately 75% of the sales revenue of AgEnergy. AgEnergy's revenues represent approximately $0.4 million of the total Eversant revenues of approximately $2.4 million, on an annual basis.

     Overall, Eversant incurred net losses of $2.1 million, $2.3 million and $2.9 million for 2001, 2000 and 1999, respectively.

Rates and Regulation

     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.

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Vermont Retail Rate Proceedings

     1997 Retail Rate Case: 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.

     In response to the Company's September 1997 rate increase 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 argued its pos ition before the Vermont Supreme Court.

     1998 Retail Rate Case: On June 12, 1998, the Company filed with the PSB for a 10.7% retail rate increase that supplanted the September 22, 1997 rate increase request of 6.6%, 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 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 was subject to retroactive or prospective adjustment upon future resolution of issues arising under the Hydro-Quebec and Vermont Joint Owner's ("VJO") Power Contract. The agreement temporarily disallowed approximately $7.4 million (based on 1999 power costs) for the Company's purchased power costs under the VJO Power Contract. As a result of the 4.7% rate increase agreement, during the fourth quarters of 1998 and 1999, the Company recorded pre-tax losses of $7.4 million and $2.9 million, respectively, 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 1999 and the first quarter of 2000, respectively. In 2000, an additional $11.5 million pre-tax loss was recorded for the estimated under-recovery of Hydro-Quebec power costs for the second, third and fourth quarters of 2000, and the first quarter of 2001. In the first quarter of 2001, an additional $2.9 million pre-tax loss was recorded for the estimated under-recovery of Hydro-Quebec power costs for the second quarter of 2001. In the second quarter of 2001, the Company reversed its $2.9 million pre-tax liability related to estimated under-recovery of Hydro-Quebec power costs and discontinued the accrual based on the favorable outcome of the Company's June 26, 2001 rate order, which is described below.

     2000 Retail Rate Case: In an effort to mitigate eroding earnings and cash flow prospects in the future, due mainly to under-recovery of power costs, on November 9, 2000, the Company filed with the PSB a request for a 7.6% rate increase ($19.0 million of annualized revenues) effective July 24, 2001. The PSB suspended the rate filing and a schedule was set to review the case.

     On February 9, 2001, the Vermont Supreme Court issued a decision on the Company's 1998 rate case appeal that reversed the PSB's decision on the preclusion issues and remanded the case to the PSB for further proceedings consistent with the Vermont Supreme Court's decision.

     The Company's June 26, 2001 rate order, which is described below, ended the uncertainty over the future recovery of Hydro-Quebec contract costs, and the Company will no longer incur future losses for under-recovery of Hydro-Quebec contract costs related to any allegations of imprudence prior to the June 26, 2001 rate order.

     On May 7, 2001, the Company and the DPS reached a rate case settlement that would end uncertainty over the future recovery of Hydro-Quebec contract costs, allow a 3.95 % rate increase, make the January 1, 1999 temporary rates permanent, permit a return on equity of 11% for the twelve months ending June 30, 2002 for the Vermont utility, and create new service quality standards. The Company also agreed to a second quarter $9.0 million one-time write-off ($5.3 million after-tax) of regulatory assets and a rate freeze through January 1, 2003.

     On June 26, 2001, the PSB issued an order on the Company's rate case settlement with the DPS. In addition to the provisions outlined above, the approved rate order requires the Company to return up to $16.0 million to ratepayers in the event of a merger, acquisition or asset sale if such sale requires PSB approval. As a result of the rate order, the 3.95% rate increase became effective with bills rendered July 1, 2001, and in June 2001 the Company

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recorded a $5.3 million after-tax loss to write-off certain regulatory assets as agreed to in the settlement. The Company was able to accept the 3.95% rate increase versus the 7.6% increase it requested since 1) regulatory asset amortizations will decrease approximately $3.5 million, on a twelve-month basis, due to the $9.0 million one-time write-off of regulatory assets and 2) Vermont Yankee decommissioning costs decreased approximately $1.9 million, on a twelve-month basis, after the rate case was filed as a result of an agreement between Vermont Yankee and the secondary purchasers.

     Deseasonalized Rates: On June 8, 2000, the PSB approved the Company's request to end the winter-summer rate differential and, therefore, the Company now has flat rates throughout a given year. Winter rates were reduced by 14.9%, while summer rates were increased by 10.5%. The rate design change was revenue neutral over a twelve-month period. The additional revenues in 2000, resulting from implementing this change in mid-year, were applied to reduce regulatory deferrals related to the Hydro-Quebec ice storm arbitration, as directed by the PSB.

New Hampshire Retail Rates

     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.

     In the third quarter of 2001, Management determined that Connecticut Valley is again subject to cost-based ratemaking and qualifies for the application of SFAS No. 71. This decision was based on the favorable Court of Appeals decision of July 25, 2000 and the subsequent denial of the NHPUC's petition for writ of certiorari by the United States Supreme Court on February 20, 2001, as well as other regulatory developments in New Hampshire during 2001. The application of SFAS No. 71 resulted in an extraordinary charge of $0.2 million for Connecticut Valley. See Note 12 to the Consolidated Financial Statements for further discussion.

Proposed Formation of Holding Company

     In order to further prepare the Company for deregulation, and to insulate the Company from the risks of its various regulated and unregulated subsidiaries, the Company filed a petition with the PSB in 1998 for permission to create a holding company that would have as subsidiaries the Company and non-utility subsidiaries, Catamount and Eversant and their subsidiaries. The proposal had been revised to have Connecticut Valley become a direct subsidiary of the holding company, rather than remain as a subsidiary of the Company. The Company believed that a holding company structure would reduce the Company's Vermont utility's cost of capital and thus would be beneficial to its ratepayers, and would also benefit any future transition to a deregulated electricity market in Vermont. The proposed holding company formation was subject to approval by Federal regulators, including the Securities and Exchange Commission, the FERC, various States and the Company's shareholders. The Company had negotiated an agreement with the DPS regarding code of conduct and affiliate transaction rules to be utilized once a holding company structure is implemented.

     As part of the settlement in the June 26, 2001 rate order, the Company and the DPS agreed to develop and file a schedule for the consideration of the holding company structure for the Company, and to submit an agreement supporting the approval of affiliate transaction rules and codes of conduct for a new holding company. The PSB approved the schedule for the holding company docket, which schedule anticipated a settlement filing, if any, in September 2001 and set forth a schedule for litigation, if necessary, beginning in December 2001. The Company and the DPS were unable to reach a resolution of issues, and the Company filed a motion to dismiss its petition. On September 24, 2001, the PSB issued its Order Closing Docket, without prejudice. The Company cannot predict whether it will request PSB approval of a holding company structure in the future.

Electric Industry Restructuring

     The electric utility industry is in a period of transition that may result in a shift away from ratemaking 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. Recent events, including those related to restructuring in California and uncertainties concerning the operations of the wholesale markets in New England, have resulted in a slowdown of the restructuring process in Vermont.

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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 proposals to restructure committed utility power supply arrangements; and 3) the PSB's Docket No. 6330, through which the PSB considered the establishment of policies and procedures to govern retail competition within the Company's service territory. At this time, the PSB has concluded its investigation into the restructuring of committed power supply arrangements in Docket No. 6140, the proceeding has been closed and the Company has actively pursued initiatives for such purposes. Additionally, in December 2001, the PSB issued an order closing Docket No. 6330. As a result, the Company cannot determine when or if retail competition will be introduced within the Company's Vermont service territory.

New Hampshire - FERC Proceedings

     On February 28, 1997, Connecticut Valley was directed by the NHPUC to terminate its purchase of power from the Company. 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 the notice of cancellation of that rate schedule (contingent upon the recovery of the stranded costs that would result from the cancellation of that rate schedule). In December 1997, the FERC rejected the Company's proposal to recover stranded costs through the imposition of a surcharge in the Company's transmission tariff, but indicated that it would consider an exit fee mechanism in the wholesale rate schedule for collecting stranded costs. The FERC denied the Company's motion for a rehearing regarding the transmission surcharge proposal. However, the Company filed a request with the FERC for an exit fee mechanism in the wholesale rate schedule to collect the stranded costs resulting from the cancellation of the wholesale rate schedule. The stranded cost obligation sought to be recovered was $90.6 million in nominal dollars and $44.9 million on a net present value basis as of December 31, 1997.

     On April 24, 2001, a FERC Administrative Law Judge ("ALJ") issued an Initial Decision in the Company's stranded cost/exit fee proceeding. The ALJ ruled that if Connecticut Valley terminates its relationship as a wholesale customer of the Company and subsequently becomes a wholesale transmission customer of the Company, Connecticut Valley shall be liable for payment of stranded costs to the Company. The ALJ calculated, on an illustrative pro-forma basis, a nominal stranded cost obligation of nearly $83.0 million through 2016. The amount of the exit fee as determined by the ALJ will decrease with each year that service continues and normal tariff revenues are collected, and will ultimately be calculated from the date of termination, if notice of termination is ever given. Absent termination of the wholesale rate schedule by mutual agreement, the earliest termination date that could presently occur pursuant to the wholesale rate schedule is December 31, 2003. The stranded c ost obligation as of December 31, 2003, expressed on a net present value basis set forth in the ALJ order, is approximately $33.9 million.

     The ALJ's Initial Decision is subject to review and approval by the FERC. If the Company is unable to obtain approval by the FERC, and if Connecticut Valley is forced to terminate its relationship as a wholesale customer of the Company, it is possible that the Company would be required to recognize a pre-tax loss under this contract totaling approximately $32.9 million as of December 31, 2003. The Company would also be required to write off approximately $0.9 million (pre-tax) of regulatory assets associated with its wholesale business as of December 31, 2003. If the Company obtains a FERC order authorizing the updated requested exit fee and notice of termination is given, Connecticut Valley will apply to the NHPUC to increase rates in order to pay the exit fee. The Company believes that the NHPUC must permit Connecticut Valley to raise rates to recover the cost of the exit fee. However, if Connecticut Valley is unable to recover its costs in rates, Connecticut Valley w ould be required to recognize the loss discussed above.

     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.

     An adverse resolution of the FERC and New Hampshire 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. See Note 12 to the Consolidated Financial Statements for additional information related to New Hampshire Retail Rates.

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

Regional Transmission Organizations (RTO)

     Pursuant to FERC Order No. 888 (issued April 1996) the Company operates its transmission system under an open access, nondiscriminatory transmission tariff.

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     On May 13, 1999, the FERC issued a notice of proposed rulemaking that would amend FERC's regulations under the Federal Power Act to facilitate the formation of regional transmission organizations ("RTO"). On December 20, 1999, the FERC issued Order No. 2000, which requires all public utilities that own, operate, or control interstate electric transmission to file a proposal for an RTO by October 15, 2000, or in the alternative, a description of any efforts by the utility to participate in an RTO, the reasons for not participating and any obstacles to participation, and any plans for further work toward such participation. The filing date for Order No. 2000 was extended to January 16, 2001 for utilities in regions with an existing independent system operator, such as ISO-New England.

     The Company, jointly with GMP, Citizens Utilities and Vermont Electric Power Company, filed its comments on the New England RTO proposal submitted by some of the New England transmission owners and ISO-New England on January 16, 2001.

     On July 12, 2001, the FERC issued an order on the New England RTO proposal, which found that the RTO proposed by the New England market participants would be insufficient in its proposed scope and regional configuration to effectively perform an RTO's required functions and to support competitive power markets. The FERC required that the participants in the proceedings involving the three proposed RTOs in the northeast, participate in mediation on forming a single Northeastern RTO. The FERC directed an Administrative Law Judge to mediate settlement discussions with the parties for a period of 45 days and file a report within 10 days (due on September 17, 2001).

     From July 24, 2001 through September 7, 2001, the Company participated in joint mediation with approximately 400 other Northeast participants to develop an RTO, which meets the requirements of Order No. 2000. The primary tasks of the mediation were focused on 1) defining the Northeastern RTO's operational paradigm, 2) developing an infrastructure and operating rules, and 3) implementing the RTO across the entire region. As directed by the FERC, the Administrative Law Judge assigned to the mediation filed a report of the mediation on September 17, 2001.

     At this time, the Company is unsure as to the outcome of this matter or its potential affects on the Company.

Competition - Risk Factors

     If retail competition is implemented in Vermont or New Hampshire, the Company is unable to predict the impact 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 and New Hampshire 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 $32.4 million on a pre-tax basis as of December 31, 2001. 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.

     SFAS No. 121, 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, 2001, based upon the regulatory environment within which the Company currently operates, SFAS No. 121 did not have an impact on the Company's regulated businesses. 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 No. 71 and 121 will continue to be applicable in the future. See Recent Accounting Pronouncements below for the new accounting standard related to impairment or disposal of long-lived assets, which replaces SFAS No. 121 effective January 1, 2002. If the Company is unable to mitigate or otherwise

Page 40 of 100

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 2.8% for 2001, 3.4% for 2000 and 2.2% for 1999. The Company's revenues, however, are based on rate regulation that generally recognizes only historical costs. Inflation therefore continues to have an impact on most aspects of the business.

Recent Accounting Pronouncements

Derivative Instruments: On January 1, 2001, the Company adopted SFAS No. 133 (subsequently amended by SFAS No. 137 and 138), Accounting for Derivative Instruments and Hedging Activities ("SFAS No. 133"). This Statement, as amended, establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. The 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.

     The Company has one long-term purchase power contract that allows the seller to purchase specified amounts of power with advance notice (Hydro-Quebec Sellback #3). This contract has been determined to be a derivative under SFAS No. 133. On April 11, 2001, the PSB approved an Accounting Order that allows the fair valuation adjustment of this contract to be deferred on the balance sheet as either a deferred asset or liability. At December 31, 2001, this derivative had an estimated fair market value of approximately a $1.0 million unrealized loss, which is included in Other deferred credits on the Consolidated Balance Sheet along with an offsetting deferred asset which is included in Other deferred charges.

Goodwill and Other Intangible Assets: In July 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets ("SFAS No. 142"), effective for fiscal years beginning after December 15, 2001. SFAS No. 142 establishes a new accounting standard for the treatment of goodwill. The new standard continues to require recognition of goodwill as an asset in a business combination but does not permit amortization as is done under current accounting standards. Effective January 1, 2002, SFAS No. 142 requires that goodwill be separately tested for impairment using a fair-value based approach as opposed to the undiscounted cash flow approach used under current accounting standards. If goodwill is found to be impaired, the Company would be required to record a non-cash charge against income, which would be recorded as a cumulative effect of a change in accounting principle. The impairment charge would be equal to the amount by which the carrying amount of the goodwill exceeds its estimated fa ir value. The Company has no goodwill related to its regulated businesses, however, Catamount has goodwill of approximately $2.0 million related to three of its investments, but does not expect an impairment resulting from the implementation of SFAS No. 142.

Asset Retirement Obligations: In August 2001, the FASB approved the issuance of SFAS No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143"). This statement provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of long-lived assets and requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The Company has identified potential retirement obligations associated with the decommissioning of its nuclear facilities, but has not yet completed its assessment. This statement is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Company has not yet quantified the impacts, if any, of adopting SFAS No. 143 on its financial statements.

Impairment or Disposal of Long-Lived Assets: In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS No. 144") which replaces SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. This statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. Although SFAS No. 144 supercedes SFAS No. 121, it retains the fundamental provisions of SFAS No. 121 regarding

Page 41 of 100

recognition/measurement of impairment of long-lived assets to be held and used and measurement of long-lived assets to be disposed of by sale. Under SFAS No. 144, asset write-downs from discontinuing a business segment will be treated the same as other assets held for sale. The new standard also broadens the financial statement presentation of discontinued operations to include the disposal of an asset group (rather than a segment of a business). SFAS No. 144 is effective beginning January 1, 2002 and, generally, is to be applied prospectively. The Company does not expect that SFAS No. 144 will have a significant impact on its financial position or results of operations.

Page 42 of 100

Item 8.    Financial Statements and Supplementary Data.

Index to Financial Statements and Supplementary Data

	Page
Report of Independent Public Accountants. . . . . . . . . . . . . . .	44
Financial Statements: Consolidated Statement of Income for each of the   three years ended December 31, 2001 . . . . . . . . . . . . . . . . Consolidated Statement of Cash Flows for each of   the three years ended December 31, 2001 . . . . . . . . . . . . . . Consolidated Balance Sheets at December 31, 2001   and 2000. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statement of Capitalization at   December 31, 2001 and 2000. . . . . . . . . . . . . . . . . . . . . Consolidated Statement of Changes in Common Stock   Equity for each of the three years ended   December 31, 2001 . . . . . . . . . . . . . . . . . . . . . . . . . Notes to Consolidated Financial Statements. . . . . . . . . . . . . .	45 46 47 48 49 50

Page 43 of 100

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

     We have audited the accompanying consolidated balance sheets and statements of capitalization of Central Vermont Public Service Corporation and its wholly-owned subsidiaries (the Company) as of December 31, 2001 and 2000, 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, 2001. 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 auditing standards generally accepted in the United States. 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, 2001 and 2000 and the results of their operations and cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States.

     As discussed in Note 12, 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 potential cancellation of the power contract between the Company and its wholly-owned subsidiary Connecticut Valley. If the power contract is ultimately cancelled and 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.

ARTHUR ANDERSEN, LLP

Boston, Massachusetts
February 4, 2002

Page 44 of 100

CONSOLIDATED STATEMENT OF INCOME
(Dollars in thousands, except per share amounts)

	Year Ended December 31
	2001	2000	1999
Operating Revenues	$302,476	$333,926	$419,815
Operating Expenses
Operation
Purchased power	147,662	185,941	269,386
Production and transmission	24,489	26,294	22,575
Other operation	43,420	44,119	46,967
Maintenance	18,264	14,813	17,613
Depreciation	17,041	16,882	16,955
Other taxes, principally property taxes	12,739	12,264	11,308
Taxes on income	11,472	9,034	10,360
Total operating expenses	275,087	309,347	395,164
Operating Income	27,389	24,579	24,651
Other Income and Deductions
Equity in earnings of affiliates	2,669	3,268	2,844
Allowance for equity funds during construction	59	69	-
Other (deductions) income, net	(16,614)	7,342	1,282
Provision for income taxes	2,964	(2,777)	(35)
Total other income and deductions, net	(10,922)	7,902	4,091
Total Operating and Other Income	16,467	32,481	28,742
Interest Expense
Interest on long-term debt	12,890	14,075	10,651
Other interest	1,018	404	1,548
Allowance for borrowed funds during construction	(30)	(41)	(41)
Total interest expense, net	13,878	14,438	12,158
Net Income Before Extraordinary Charge	2,589	18,043	16,584
Extraordinary Charge, Net of Taxes	182	-	-
Net Income	2,407	18,043	16,584
Preferred Stock Dividends Requirements	1,696	1,779	1,862
Earnings Available For Common Stock	$      711	$  16,264	$  14,722
Average Shares of Common Stock Outstanding	11,551,042	11,488,351	11,463,197
Basic and Diluted Share of Common Stock:
Earnings before extraordinary charge	$.08	$1.42	$1.28
Extraordinary charge	.02	-	-
Earnings Per Basic and Diluted Share of Common Stock	$.06	$1.42	$1.28
Dividends Paid Per Share of Common Stock	$.88	$ .88	$ .88

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

Page 45 of 100

CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in thousands)

	Year Ended December 31
	2001	2000	1999
Cash Flows Provided (Used) By:
Operating Activities
Net income	$2,407	$18,043	$16,584
Adjustments to reconcile net income to net cash provided by operating activities
Extraordinary charge	182	-	-
Equity in earnings of affiliates	(2,669)	(3,268)	(2,844)
Dividends received from affiliates	2,773	4,315	2,739
Equity in earnings from non-utility investment	(6,079)	(1,223)	795
Distribution of earnings from non-utility investments	4,636	4,457	4,390
Depreciation	17,041	16,882	16,955
Regulatory asset write-off	9,000	-	-
Asset impairment charges (including tax valuation allowance)	8,905	1,000	-
Investment write-down	1,963	-	-
Amortization of capital leases	1,089	1,089	1,093
Deferred income taxes and investment tax credits	(5,083)	(3,861)	1,971
Net (deferral) and amortization of nuclear replacement            energy and maintenance costs	(2,517)	6,207	(4,914)
Amortization of conservation and load management costs	3,144	5,339	6,613
Net (deferral) and amortization of restructuring costs	(1,328)	115	-
Decrease (increase) in accounts receivable and unbilled revenues	4,746	15,754	(11,138)
(Decrease) increase in accounts payable	(3,712)	(6,597)	3,315
(Decrease) increase in accrued income taxes	(1,614)	753	(2,300)
Change in other working capital items	(6,532)	3,029	588
Change in environmental reserve	(285)	(275)	68
Other, net	4,149	(892)	(2,683)
Net cash provided by operating activities	30,216	60,867	31,232
Investing Activities
Construction and plant expenditures	(16,553)	(14,968)	(13,231)
Conservation and load management expenditures	(504)	(1,136)	(2,440)
Return of capital	641	488	186
Proceeds from sale of assets	-	-	88
Non-utility investments	(13,671)	(4,634)	(14,338)
Other investments, net	(474)	(134)	(198)
Net cash used for investing activities	(30,561)	(20,384)	(29,933)
Financing Activities
Sale of common stock	556	534	75
Short-term debt, net	-	17	(40,585)
Long-term debt, net	9,796	(14,776)	78,674
Retirement of preferred stock	-	(1,000)	(1,000)
Common and preferred dividends paid	(11,433)	(11,888)	(11,950)
Reduction in capital lease obligations	(1,089)	(1,089)	(1,092)
Other	20	244	(11)
Net cash used for financing activities	(2,150)	(27,958)	24,111
Net (Decrease) Increase In Cash and Cash Equivalents	(2,495)	12,525	25,410
Cash and Cash Equivalents at Beginning of Year	47,986	35,461	10,051
Cash and Cash Equivalents at End of Year	$45,491	$47,986	$35,461
Supplemental Cash Flow Information
Cash paid during the year for:
Interest (net of amounts capitalized)	$13,871	$13,862	$  9,207
Income taxes (net of refunds)	$16,892	$15,118	$10,935
Non-cash Operating, Investing and Financing Activities
Stock award plans (Note 6)
Regulatory assets (Notes 1, 2 and 12)
Long-term lease arrangements (Note 13)
The accompanying notes are an integral part of these consolidated financial statements.

Page 46 of 100

CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)

	December 31
	2001	2000
Assets
Utility Plant, at original cost	$490,137	$478,324
Less accumulated depreciation	198,087	183,828
	292,050	294,496
Construction work-in-progress	15,727	15,197
Nuclear fuel, net	852	1,283
Net utility plant	308,629	310,976
Investments and Other Assets
Investments in affiliates, at equity	23,823	24,527
Non-utility investments	49,543	46,591
Non-utility property, less accumulated depreciation	2,401	2,172
Total investments and other assets	75,767	73,290
Current Assets
Cash and cash equivalents	45,491	47,986
Special deposits	7	118
Accounts receivable, less allowance for uncollectible accounts             ($2,071 in 2001 and $1,655 in 2000)	21,951	25,006
Unbilled revenues	16,404	17,142
Materials and supplies, at average cost	4,167	3,702
Prepayments	3,676	2,593
Other current assets	5,408	6,511
Total current assets	97,104	103,058
Regulatory Assets	32,403	45,797
Other Deferred Charges	7,771	6,717
Total Assets	$521,674	$539,838
Capitalization and Liabilities
Capitalization
Common stock equity	$183,514	$190,697
Preferred and preference stock	8,054	8,054
Preferred stock with sinking fund requirements	15,000	16,000
Long-term debt	159,771	152,975
Capital lease obligations	12,897	13,978
Total capitalization	379,236	381,704
Current Liabilities
Current portion of preferred stock	1,000	-
Current portion of long-term debt	7,225	4,205
Accounts payable	4,796	6,407
Accounts payable - affiliates	12,092	13,523
Accrued income taxes	74	1,428
Dividends declared	2,978	2,532
Nuclear decommissioning costs	2,298	2,214
Disallowed purchased power costs	-	2,934
Other current liabilities	19,739	23,117
Total current liabilities	50,202	56,360
Deferred Credits
Deferred income taxes	38,828	43,779
Deferred investment tax credits	5,658	6,049
Nuclear decommissioning costs	12,826	14,737
Other deferred credits	34,924	37,209
Total deferred credits	92,236	101,774
Commitments and Contingencies
Total Capitalization and Liabilities	$521,674	$539,838

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

Page 47 of 100

CONSOLIDATED STATEMENT OF CAPITALIZATION
(Dollars in thousands)

	December 31
	2001	2000
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	47,634	45,810
Accumulated other comprehensive income	(623)	(269)
Deferred compensation plans-employee stock ownership plans	(1,097)	(358)
Treasury stock (175,165 shares and 277,868 shares, respectively, at cost)	(2,285)	(3,624)
Retained earnings	69,170	78,423
Total common stock equity	183,514	190,697
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; 160,000 shares	16,000	16,000
Preferred stock, $25 par value, authorized 1,000,000 shares
Outstanding - none	-	-
Preference stock, $1 par value, authorized 1,000,000 shares
Outstanding - none	-	-
	24,054	24,054
Less current portion	1,000	-
Total cumulative preferred and preference stock	23,054	24,054
Long-Term Debt
First Mortgage Bonds
9.26% Series GG, due 2002	3,000	3,000
9.97% Series HH, due 2003	7,000	11,000
8.91% Series JJ, due 2031	15,000	15,000
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	75,000
Vermont Industrial Development Authority Bonds
Variable, due 2013 (1.65% at December 31, 2001)	5,800	5,800
New Hampshire Industrial Development Authority Bonds
5.50%, due 2009	5,500	5,500
Connecticut Development Authority Bonds
Variable, due 2015 (1.80% at December 31, 2001)	5,000	5,000
Other, various	22,696	8,880
	166,996	157,180
Less current portion	7,225	4,205
Total long-term debt	159,771	152,975
Capital Lease Obligations	12,897	13,978
Total Capitalization	$379,236	$381,704

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

Page 48 of 100

CONSOLIDATED STATEMENT OF CHANGES IN COMMON STOCK EQUITY
(Dollars in thousands)

	Common Stock   Shares          Amount		Other Paid-in Capital	Deferred Compensation Plan - Employee Stock	Accumulated Other Comprehensive Income	Treasury Stock	Retained Earnings	Total
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
Treasury stock at cost	41,175					535		535
Adjustments to Treasury stock    for option plans							(93)	(93)
Net income							18,043	18,043
Other comprehensive income net of taxes					(23)			(23)
Allocation of benefits - employee stock				$233				233
Unearned stock compensation			448	(591)				(143)
Cash dividends on capital stock:
Common stock - $.88 per share							(10,118)	(10,118)
Cumulative preferred stock:
Non-redeemable							(369)	(369)
Redeemable							(1,411)	(1,411)
Amortization of preferred stock    issuance expenses			22					22
Balance, December 31, 2000	11,507,980	$70,715	$45,810	$(358)	$(269)	$(3,624)	$78,423	$190,697
Treasury stock at cost	102,703					1,339		1,339
Adjustments to Treasury stock    for option plans							(41)	(41)
Net income							2,407	2,407
Other comprehensive income net of taxes					(354)			(354)
Allocation of benefits - employee stock				1,074				1,074
Unearned stock compensation			1,802	(1,813)				(11)
Cash dividends on capital stock:
Common stock - $.88 per share							(10,183)	(10,183)
Cumulative preferred stock:
Non-redeemable							(368)	(368)
Redeemable							(1,328)	(1,328)
Amortization of preferred stock    issuance expenses			22					22
Other adjustments							260	260
Balance, December 31, 2001	11,610,683	$70,715	$47,634	$(1,097)	$(623)	$(2,285)	$69,170	$183,514

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

Page 49 of 100

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 Vermont Public Service Board ("PSB"), the New Hampshire Public Utilities Commission ("NHPUC") and the Federal Energy Regulatory Commission ("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 Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation" ("SFAS No. 71"), for its regulated Vermont service territory, FERC-regulated wholesale business and its wholly owned subsidiary, Connecticut Valley Electric Company Inc.'s ("Connecticut Valley") New Hampshire service territory. 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, w hether due to competition or regulatory action, this accounting standard 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 future recovery of its regulatory assets in the State of Vermont and the State of New Hampshire f or the Company's retail and wholesale businesses are probable.

     In the third quarter of 2001, Management determined that Connecticut Valley is again subject to cost-based ratemaking and qualifies for application of SFAS No. 71. This decision was based on the favorable Court of Appeals decision of July 25, 2000, the subsequent denial of the NHPUC's petition for writ of certiorari by the United States Supreme Court on February 20, 2001 and other regulatory developments in New Hampshire during 2001. In 1998, Management had discontinued the application of SFAS No. 71 related to Connecticut Valley. For additional information see Note 12 below.

Unregulated Business Results of operations of the Company's two wholly owned non-regulated subsidiaries, Catamount Energy Corporation ("Catamount") and Eversant Corporation ("Eversant", formerly SmartEnergy Services, Inc.), 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 associated with investments in new projects. Catamount's project 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. Investments in joint ventures and in partnerships over which Catamount does not have a controlling financial interest are accounted for using the equity method. Under this method, Catamount records it s ownership share of the net income or loss of each venture in the accompanying consolidated financial statements.

     In the fourth quarter of 2001, Catamount recorded asset impairment charges related to four of its investments in non-regulated energy generation projects, in accordance with SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" ("SFAS No. 121"). For additional information see Note 3 below.

Revenues Estimated unbilled revenues are recorded at the end of each quarterly accounting period. For 2000 and 1999, operating revenues include $22.2 million and $100.1 million, respectively, related to the Alliance with Virginia Power, which was effectively terminated by the Company during the third quarter of 1999 with related revenues ending in December 2000.

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.

Page 50 of 100

Depreciation The Company uses the straight-line remaining life method of depreciation. Total depreciation expense was 3.54%, 3.57% and 3.53% of the cost of depreciable utility plant for each of the years 1999 through 2001, respectively.

Income Taxes In accordance with SFAS No. 109, "Accounting for Income Taxes" ("SFAS No. 109"), 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. Valuation allowances are provided when necessary against certain deferred tax assets.

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 ratemaking proceedings. AFDC equity represents a current non-cash credit to earnings, recoverable over the life of the property. The AFDC rates used by the Company were 5.52%, 9.30% and 9.40% for the years 1999 through 2001, respectively.

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

	2001	2000
Conservation and load management (a)	$4,633	$10,212
Restructuring costs	59	2,472
Nuclear refueling outage costs (a)	4,445	1,928
Income taxes (b)	6,770	7,047
Year 2000 costs and technology initiatives	-	2,322
Dismantling costs (c):
Maine Yankee nuclear power plant	10,612	11,505
Connecticut Yankee nuclear power plant	4,513	5,446
Hydro-Quebec arbitration costs, net of deseasonalized    revenue impact for 2000	- -	2,531
Unrecovered plant and regulatory study costs	1,310	1,510
Other regulatory assets	61	824
	$32,403	$45,797
(a)  The Company earns a return on unamortized Conservation and Load Management costs and        replacement energy and maintenance costs related to scheduled nuclear refueling outages.
(b)  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.
(c)  Recovery for the unamortized dismantling costs for Connecticut Yankee and Maine Yankee is        provided without a return on investment through 2007 and 2008, respectively. See Note 2 below        for discussion of the costs associated with the discontinued operations of the nuclear power plants.

     As a result of the June 26, 2001 approved rate order, the Company wrote off $9.0 million (pre-tax) of regulatory assets, in the second quarter of 2001, related to Conservation and Load Management ("C&LM") costs, Year 2000 costs and technology initiatives, restructuring costs, and other costs as agreed to with the PSB. In addition, the Company agreed that all amounts collected based on the award issued by the Hydro-Quebec arbitration panel would be applied first to reduce the balance of the deferred costs related to the ice storm arbitration, with the remaining balance applied to reduce other regulatory asset accounts as specified by the Vermont Department of Public Service ("DPS") and approved by the PSB. See Note 12 for discussion of the Vermont rate case settlement.

     In July 2001, the Company received its share of the settlement with Hydro-Quebec of $4.3 million, and applied approximately $2.7 million to the remaining balance of the deferred costs related to the ice storm arbitration. On October 30, 2001, the Company filed a letter with the PSB summarizing its agreement with the DPS on application of the remaining $1.6 million of the Hydro-Quebec settlement to remaining regulatory assets, which agreement is subject to approval by the PSB. Currently, the remaining $1.6 million balance is included as a deferred credit on the Company's Consolidated Balance Sheet. See Note 13 for discussion of the Hydro-Quebec contract.

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     During the first six months of 2001, Vermont Yankee and Millstone Unit #3 had scheduled refueling outages. During regular nuclear refueling outages, in accordance with ratemaking treatment, the incremental costs attributable to replacement energy purchased from ISO-New England or other parties in New England and maintenance costs are deferred and amortized ratably to expense until the next regularly scheduled refueling outage.

Purchased Power The Company records the annual cost of power obtained under long-term contracts as operating expenses. Since these contracts, more fully described in Note 13, 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. Purchased power in 2000 and 1999 includes $22.0 million and $100.6 million, respectively, related to the Alliance with Virginia Power, which was effectively terminated by the Company during the third quarter of 1999 with related purchases ending in December 2000.

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 unregulated investments, 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 review, certain of Catamount's assets are impaired at December 31, 2001. See Note 3 to the Consolidated Financial Statements for further discussion.

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.

Reclassifications The Company will record reclassifications to the financial statements of the prior year when considered necessary or to conform to current year presentation.

Statement of Cash Flows The Company considers all highly liquid investments with an original 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):

		December 31
	Ownership	2001	2000
Nuclear generating companies:
Vermont Yankee Nuclear Power Corporation (1)	31.3%	$16,818	$16,863
Connecticut Yankee Atomic Power Company	2.0%	1,349	1,501
Maine Yankee Atomic Power Company	2.0%	1,257	1,400
Yankee Atomic Electric Company	3.5%	28	283
		19,452	20,047
Vermont Electric Power Company, Inc.:
Common stock	56.8%	3,710	3,575
Preferred stock		661	905
		$23,823	$24,527
(1) The Company's ownership percentage in Vermont Yankee has changed to 33.23% in the first quarter        of 2002 related to the buy-back of shares held by minority owners of the plant, which is explained        below.

     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 its entitlement percentage in Vermont Yankee is 35%. The Company is obligated

Page 52 of 100

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.

Vermont Yankee

     Vermont Yankee's current decommissioning cost study is based on a 1994 site study stated in 1993 dollars. The FERC-approved settlement agreement allowed $312.7 million as the estimated decommissioning cost. Based on the study's assumed cost escalation rate of 4.25% per annum and an expiration of the plant's operating license in the year 2012, the estimated current cost of decommissioning is $471.1 million at the end of 2001 and, at the end of 2012, is approximately $721.8 million. At December 31, 2001, the market value of the Vermont Yankee Decommissioning Trust Fund was approximately $297.1 million. Based on the total estimated costs to decommission the plant in 2012, the Company's decommissioning obligation is approximately $148.7 million, which represents the value of payments and accrued earnings in the decommissioning trust fund to accomplish the level of funding required at 2012.

     Under the FERC-approved settlement agreement, Vermont Yankee was required to file with the 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. If the plant is not sold, Vermont Yankee will need to submit a new decommissioning filing to the FERC. The sale of the plant would transfer responsibility for decommissioning the plant to the new owner and make a revised schedule of decommissioning unnecessary.

     On February 14, 2001, the PSB issued its Order Dismissing Petition in Docket No. 6300, the proceeding in which the Company, along with Green Mountain Power ("GMP"), Vermont Yankee and AmerGen Energy Company ("AmerGen") sought PSB approval of the sale of the Vermont Yankee nuclear plant to AmerGen. In this Order, the PSB determined that the proposed purchase price, as filed in November 2000, pursuant to a Memorandum of Understanding, did not reflect the fair market value of the plant and, therefore, the sale did not promote the general good of the State of Vermont. This ruling was consistent with the Company's position. The PSB dismissed the petition for approval in March 2001. The management of Vermont Yankee subsequently concluded that selling the plant at auction would provide the greatest benefit to the owners and consumers. The investment banking firm of JPMorgan was retained by Vermont Yankee as the exclusive financial advisor for the auction.

     As a result of issues raised related to the cancelled AmerGen sale, Vermont Yankee reached an agreement in principle with the Vermont Yankee sponsors and their secondary power purchasers, the DPS and the FERC staff that reduces the Vermont Yankee cost of service the sponsors and the secondary purchasers will expect to pay through 2012. The agreement is reflected in billings to sponsors and secondary purchasers effective July 2001. The FERC approved the agreement on September 13, 2001.

     On August 15, 2001, Vermont Yankee announced that a sales agreement had been reached with Entergy Corporation ("Entergy") for $180 million, representing $145 million for the plant and related assets and $35 million for nuclear fuel. Entergy will also assume decommissioning liability for the plant and its decommissioning trust fund. The agreement includes a purchase power contract with prices that generally range from 3.9 cents to 4.5 cents per kilowatt-hour subject to a "low-market adjuster" that protects the current Vermont Yankee owner-utilities, including the Company and its power consumers, in the event power market prices drop significantly. On September 27, 2001, the Company filed testimony with the PSB in support of the sale. In an order entered October 26, 2001, the PSB granted intervention to several parties that the Company did not oppose, and established a schedule that provides for discovery, hearings and final briefing by April 29, 2002. Certain of the inter venors were secondary purchasers of Vermont Yankee power, which were seeking adjustments in their power purchase contracts, and stockholders of Vermont Yankee, which were asserting dissenters' rights. On January 16, 2002, Vermont Yankee announced that it had reached an agreement with the secondary purchasers and had purchased back the shares held by the minority stockholders; these parties have requested to withdraw from the PSB proceeding.

     On January 7, 2002, the DPS and the remaining intervenors prefiled their direct testimony in the PSB proceeding. Initial hearings occurred during the first week of February 2002 with prefiled rebuttal testimony due on February 25, 2002, and rebuttal hearings March 18 through March 22, 2002. The current schedule in the PSB proceeding could permit a closing, if the sale is approved, by the end of July 2002. The Company cannot predict the outcome of the proceedings.

Page 53 of 100

     The sale is also subject to other regulatory approvals including the Nuclear Regulatory Commission and the Securities and Exchange Commission.

Maine Yankee

     In 1997, the Maine Yankee nuclear power plant was prematurely retired from commercial operation. The Company relied on Maine Yankee for less than 5% of its required system capacity.

     Maine Yankee's total estimated decommissioning costs, based on a 1998 study, amounts to approximately $536.0 million in 1998 dollars. In January 2002, Maine Yankee and Federal Insurance agreed on a settlement of the pending litigation arising from contractor performance when the original contractor, Stone and Webster, went into bankruptcy. A settlement payment of $44.0 million has been deposited into the Maine Yankee Decommissioning Trust Fund. Future payments for the closing, decommissioning and recovery of the remaining investment in Maine Yankee, including the insurance settlement, are currently estimated to be approximately $494.2 million; the Company's share is expected to be approximately $9.9 million to be paid over the period 2002 through 2008.

     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 issues raised by the secondary purchasers, who purchased Maine Yankee power through agreements with the original owners, limiting the amounts they will pay for decommissioning the Maine Yankee plant and settling other points of contention affecting individual secondary purchasers.

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.

     Connecticut Yankee's estimated decommissioning costs, based on a July 2000 settlement with the FERC and the intervenors, amounts to approximately $569.0 million in January 2000 dollars. The settlement rates became effective September 1, 2000, following the FERC order of July 26, 2000. Future payments for the closing, decommissioning and recovery of the remaining investment in Connecticut Yankee are currently estimated to be approximately $226.6 million; the Company's share is expected to be approximately $4.5 million to be paid over the period 2002 through 2007.

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. As of July 2000, Yankee Atomic had collected from its sponsors sufficient funds, based on a current forecast, to complete the decommissioning effort and to recover all other FERC-approved costs of service. Therefore, Yankee Atomic discontinued billings to its sponsors pending the need to increase or decrease the funds available for the completion of its financial obligations, including decommissioning. Such a change would require a FERC review and approval.

Maine Yankee, Connecticut Yankee and Yankee Atomic Decommissioning Costs

     Currently, costs billed to the Company by Maine Yankee and Connecticut Yankee, including a provision for ultimate decommissioning of the units, are being collected from the Company's customers through existing retail and wholesale rate tariffs. As of December 31, 2000, the Company has completed its obligation for decommissioning costs based on current estimates related to Yankee Atomic. The Company's share of remaining costs with respect to Maine Yankee and Connecticut Yankee's decisions to discontinue operation were estimated to be $10.6 million and $4.5 million, respectively, at December 31, 2001. These amounts are subject to ongoing review and revisions, and are reflected in the accompanying Consolidated Balance Sheet both as regulatory assets and nuclear dismantling liabilities (current and non-current). In the first quarter of 2002, the Company plans to revise its estimated share of remaining costs related to Maine Yankee to reflect the impacts of the insurance s ettlement described above.

     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. This would have the effect of lowering costs to customers. 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.

Page 54 of 100

Nuclear Insurance

     The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $9.5 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 $9.3 billion per incident by assessing $88.1 million against each of the 106 reactor units that are currently subject to the Program in the United States, limited to a maximum assessment of $10.0 million per incident per nuclear unit in any one year. The maximum assessment is adjusted at least every five years to reflect inflationary changes. The Price-Andersen Act has been renewed three times since it was first enacted in 1957. The Act is set to expire in August 2002 and Congress is currently considering reauthoriz ation of this legislation. 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	2001	2000	1999
Operating revenues	$178,840	$178,294	$208,812
Operating income	$  11,983	$  16,144	$  14,932
Net income	$    6,119	$    6,583	$    6,471
Company's equity in net income	$    1,912	$    2,052	$    2,022

	December 31
Investment	2001	2000
Current assets	$   35,344	$   37,186
Non-current assets	688,471	669,798
Total Assets	723,815	706,984
Less:
Current liabilities	64,082	72,156
Non-current liabilities	605,558	580,507
Net assets	$   54,175	$   54,321
Company's equity in net assets	$   16,818	$   16,863

     Included in Vermont Yankee's revenues shown above are sales to the Company of $56.1 million, $55.5 million and $65.0 million for 2001, 2000 and 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.

     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 midnight, June 30, 1985, and was extended thereafter as follows until June 30, 1986, with an automatic renewal from year to year unless, at least 90 days prior to any succeeding anniversary, any party were to notify the other parties in writing that it desired to terminate the agreement as of such anniversary. By an Amendment to the 1985 Four-Party Agreement dated February 1, 1987, the Agreement continued until May 1, 1987 and thereafter for additional two-year terms, unless at least 90 days prior to any two-year anniversary, any party were to 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.

Page 55 of 100

     In December 1985, the Company, VELCO and the two other major distribution companies entered into the 1985 Option Agreement (as amended) for the purpose of modifying the terms of an option to purchase certain facilities owned by VELCO, but located in the individual company's service territory, which were originally outlined in the Four-Party Agreement. The option was extended from time to time and expired on December 31, 2001. The Company and the other parties to the Option Agreement are currently negotiating an extension to the Option Agreement.

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

Earnings	2001	2000	1999
Transmission revenues	$19,785	$17,711	$16,935
Operating income	$  3,588	$  2,684	$  2,633
Net income	$  1,052	$  1,257	$  1,221
Company's equity in net income	$     585	$     645	$     638

Investment	December 31
	2001	2000
Current assets	$21,650	$22,713
Non-current assets	67,720	61,098
Total assets	89,370	83,811
Less:
Current liabilities	22,026	32,840
Non-current liabilities	59,423	42,721
Net assets	$  7,921	$  8,250
Company's equity in net assets	$  4,371	$  4,480

     Included in VELCO's revenues shown above are transmission services to the Company (reflected as production and transmission expenses in the accompanying Consolidated Statement of Income) amounting to $10.5 million, $9.8 million and $8.6 million for 2001, 2000 and 1999, respectively.

Note 3
Non-utility investments

Catamount

     The Company's wholly owned subsidiary, Catamount Energy Corporation, a subsidiary of Catamount Resources Corporation, invests through its wholly owned subsidiaries, in non-regulated, wind energy-supply projects in North American and Western Europe. Catamount's after-tax loss for 2001 was $8.7 million, primarily resulting from fourth quarter 2001 asset impairment charges related to four of its investments as a result of writing down two assets held for sale to estimated sales value (Gauley River Power Partners, L.P. and Fibrothetford Limited) and issues concerning the future viability of two other operating projects (Rupert Cogeneration and Glenns Ferry Cogeneration). After-tax earnings were $0.7 million and $2.1 million for 2000 and 1999, respectively. Certain financial information for Catamount's investments is set forth in the table that follows (dollars in thousands):

Projects	Location	Generating Capacity	Fuel	In-Service Date	Ownership	Investment December 31    2001          2000
Rumford Cogeneration	Maine	85 mW	Coal/Wood	1990	15.1%	$18,086	$15,858
Ryegate Associates	Vermont	20 mW	Wood	1992	33.1%	6,544	6,392
Appomattox Cogeneration	Virginia	41 mW	Coal/Biomass Black liquor	1982	25.3%	6,560	4,699
Rupert Cogeneration Partners	Idaho	10 mW	Gas	1996	50.0%	-	1,931
Glenns Ferry Cogeneration	Idaho	10 mW	Gas	1996	50.0%	-	1,722
Fibrothetford Limited	England	38.5 mW	Biomass	1998	44.7%	2,529	6,258
Heartlands Power Limited	England	98 mW	Gas	1999	50.0%	6,377	7,360
Gauley River Power Partners	West Virginia	80 mW	Water	2001	50.0%	8,500	(100)
DK Burgerwindpark Eckolstadt	Germany	13 mW	Wind	2000	10.0%	356	308
DK Windpark Kavelstorf GmbH&Co. KG	Germany	7.2 mW	Wind	2001	10.0%	143	139
						$49,095	$44,567

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     At December 31, 2001, Gauley River Power Partners, L.P. ("Gauley River") and Thetford Limited ("Thetford") were classified as held-for-sale. In the fourth quarter, in accordance with SFAS No. 121, Catamount recorded an after-tax impairment charge to earnings of $1.4 million associated with its interests in Gauley River and an after-tax impairment charge to earnings of $3.2 million associated with its interest in Fibrothetford. The Gauley River impairment was based on bids received from third parties, less estimated costs to sell. The impairment charge for Fibrothetford was based on review of expected future cash flows and expected market value of Catamount's interest given the project's current financial condition.

     Although Catamount has a controlling interest in Gauley River, this investment has not been consolidated in the accompanying financial statements since it is Management's intent to sell this project and therefore control is considered temporary. For equity accounting purposes, the Gauley River investment is treated as a 100% ownership investment. Included in the $8.5 million December 31, 2001 investment balance is a $1.0 million equity investment which will be funded by March 31, 2002.

     In the fourth quarter of 2001, Catamount recorded impairment charges for all of its interests in the Glenns Ferry and Rupert projects for a total after-tax charge of $3.0 million. The impairment charges were the result of the deteriorating financial condition of the projects' steam hosts that are essential to the projects' Qualifying Facility status and long-term viability. The steam hosts are actively seeking resolution of their current financial issues; however, Management cannot predict whether they will ultimately be successful. Also see Note 7, Long-term debt, for additional information.

Eversant

     Eversant, also a subsidiary of Catamount Resources Corporation, invests in unregulated energy and service-related businesses. Eversant had a 13.4% ownership interest, on a fully diluted basis, in Home Service Store ("HSS") as of December 31, 2001. HSS establishes a network of affiliate contractors who perform home maintenance repair and improvements via membership. HSS began operations in 1999 and is subject to risks and challenges similar to a company in the early stage of development. HSS launched a Commercial Services division in 2001, which meets the needs of small businesses, building owners and property managers. In May 2001, Eversant entered into a convertible loan agreement with HSS and Jupiter Capital ("Jupiter"). Under the agreement, Eversant loaned HSS $2.0 million and Jupiter loaned HSS $5.0 million, which, along with current debt balances and accrued interest, was converted to preferred securities when HSS received an additional cash investment from Jup iter in August 2001. In September 2001, Eversant recorded a $1.2 million after-tax write-down of its investment in HSS to fair market value. Eversant has previously recorded losses of $9.0 million related to its investment in HSS. At year end, Jupiter committed, based upon continued satisfactory operating progress, to provide an additional $5.0 million in funding to the business over time. The first $1.0 million was invested in December 2001 and Jupiter received options to acquire up to an aggregate of $4.0 million in preferred securities. In January 2002, Jupiter invested an additional $1.0 million and predicts that an additional $2.0-$3.0 million in funding above the $5.0 million may be required and they are currently talking to other parties about providing this capital. Eversant's fully diluted ownership position after the $5.0 million Jupiter investment would be 12.6%.

     Eversant's share of the HSS losses for 2001 was zero as the Company's equity investment was reduced to zero as a result of losses incurred to date. As of December 31, 2001, Eversant has a preferred equity investment in HSS of $1.4 million, recorded at estimated fair value.

     During 2001, AgEnergy (formerly SmartEnergy Control Systems), a wholly owned subsidiary of Eversant, filed a claim in arbitration against Westfalia-Surge, the exclusive distributor that markets and sells its SmartDrive Control product. The arbitration concerned the Company's claim that Westfalia-Surge had not conducted itself in accordance with the exclusive distributorship agreement between the parties. On January 28, 2002, the Company received an adverse decision related to the arbitration proceeding with Westfalia-Surge. The Company does not expect a material liability related to the decision and is currently in discussions with Westfalia-Surge regarding this matter. The SmartDrive Control product has generated approximately 75% of the sales revenue of AgEnergy. AgEnergy's revenues represent approximately $0.4 million of the total Eversant revenues of approximately $2.4 million, on an annual basis.

     Overall, Eversant incurred net losses of $2.1 million, $2.3 million and $2.9 million for 2001, 2000 and 1999, respectively.

Page 57 of 100

Note 4
Common stock

     Through a common stock repurchase program that 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 187,282 shares sold in connection with the Company's stock option plans, are recorded as treasury stock, at average cost, in the Company's Consolidated Balance Sheets.

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 award plans

Stock Option Plans

     The Company has awarded stock options to key employees and non-employee directors under various option plans approved in 1988, 1993, 1997, 1998 and 2000 that authorized the granting of options with respect to 1,375,875 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 and the maximum term of an option may not exceed five and ten years for non-employee directors and key employees, respectively. Shares available for future grants under the 1997, 1998 and 2000 stock option plans were 254,440 at December 31, 2001. No additional grants may be given under the 1988 and 1993 plans. Option activity during the past three years was as follows:

	Average Option Price	Stock  Options
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
Options exercised	10.7840	(23,700)
Options granted	10.7626	100,550
Options expired	15.4596	(128,725)
Options outstanding at December 31, 2000	$13.8067	532,985
Options exercised	12.4356	(98,550)
Options granted	16.1295	121,150
Options expired	18.6255	( 31,500)
Options outstanding at December 31, 2001	$13.6050	524,085

     The price range of options outstanding at December 31, 2001 is $10.5625 to $24.3125. The weighted average remaining contractual life at December 31, 2001 is 6.83 years and the weighted average exercise price is $13.6050. Exercisable options at December 31, 2001 total 494,585 and the weighted average exercise price is $13.5794.

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     The Company accounts for these plans under Accounting Principles Board Opinion No. 25 ("APB 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):

		2001	2000	1999
Net Income	As reported    Pro forma	$2,407 $2,289	$18,043 $17,959	$16,584 $16,518
Earnings per share    of common stock	As reported    Pro forma	$.06      $.05	$1.42     $1.41	$1.28     $1.27

     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:

	2001	2000	1999
Volatility	.3328	.2872	.2982
Risk-free rate of return	5.75%	6.50%	5.50%
Dividend yield	7.42%	7.32%	7.26%
Expected life in years	5-10	5-10	5-10

Restricted Stock Plans

Annual Incentive Program

     Restricted stock performance awards have been granted to certain executive officers for the Company's annual Management Incentive Plan, under the 1997 Restricted Stock Plan for Non-employee Directors and Key Employees ("Restricted Plan"), including dividends and voting rights. Restricted stock was granted to non-employee directors for 50% of their annual retainer.

     Recipients are not required to provide consideration to the Company under the Restricted Plan, other than rendering service, and have the right to vote the shares and to receive dividends under the Restricted Plan.

     In accordance with APB 25, compensation cost is recognized for Restricted Plan shares, over the applicable vesting period, for the fair value of the restricted stock awarded, which is its market value without restrictions at the date of grant. Because this type of plan is classified as a variable plan, interim estimates of compensation are required based on a combination of the then-fair market value of the stock as of the end of the reporting period and the extent or degree of compliance with the performance criteria.

     A total of 5,813 Restricted Plan shares were issued at an average market value of $15.63 in 2001, 17,475 shares at an average market value of $10.64 in 2000 and 3,424 shares at an average market value of $11.67 in 1999. These awards are recorded at the market value on the date of grant. A total of 1,660 shares were forfeited at an average market value of $10.99 in 2001. Initially, the total market value of the shares is treated as deferred compensation and is charged to expense over the respective vesting periods.

     Restricted Plan stock expense was $97,161 for 2001, $74,395 for 2000 and $39,968 for 1999.

Long-term Incentive Plan

     Restricted performance shares have been awarded for the Company's three-year vesting, Long-Term Incentive Plan, for executive officers, under the 1999, 2000 and 2001 Performance Share Incentive Plans ("Performance Plans").

     The restricted stock awards under the Performance Plans will vest only if the Company achieves certain financial goals over three-year performance cycles. Recipients are not required to provide consideration to the Company under the Performance Plans, other than rendering service.

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     Under APB No. 25, for Performance Plan shares, adjustments are made to expense for changes in market value, achievement of financial goals and changes in employment, prior to completion of the performance cycle. Initially, the total market value of the shares is treated as deferred compensation and is charged to expense over the respective performance cycles.

     Performance Plan stock compensation charged to expense was $1,014,851, $200,712 and $0 for the years 2001, 2000 and 1999, respectively.

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%.

     Based on outstanding debt at December 31, 2001, the aggregate amount of utility long-term debt maturities and sinking fund requirements are $7.0 million, $10.5 million, $75.0 million, $0.0 million and $0.0 million for the years 2002 through 2006, respectively. Substantially all Vermont utility property and plant is subject to liens under the First and Second Mortgage Bonds.

     The Company's long-term debt contains financial and non-financial covenants. At December 31, 2001, the Company was in compliance with all debt covenants related to its various debt agreements.

     Financial obligations of the Company's subsidiaries are non-recourse to the Company. On April 25, 2001, the Company sought, and in June 2001, the Company received unanimous approval from its First Mortgage Bondholders to enter into a 42nd Supplemental Indenture to the Company's Mortgage dated October 1, 1929 (the "First Mortgage") to exclude its wholly owned non-regulated subsidiary, Catamount Resources Corporation and its subsidiaries (currently Catamount and Eversant), from the term "subsidiary" under the Mortgage. The 42nd Supplemental Indenture (amendment) eliminates the possibility of cross defaults under the First Mortgage occasioned by a default on the indebtedness of Catamount Resources Corporation or its subsidiaries. Additionally, the amendment imposes limitations on the level of the Company's future investment in non-regulated subsidiaries.

Non-Utility

     In 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, of which $21.3 million was outstanding at December 31, 2001. The interest rate is variable, prime-based. Catamount's assets secure the facility. Based on total outstanding debt of $21.5 million at December 31, 2001, the aggregate amount of Catamount's long-term debt maturities are $0.0 million, $3.2 million, $4.2 million, $5.0 million and $9.1 million for the years 2002 through 2006, respectively. Catamount's long-term debt contains financial and non-financial covenants. At December 31, 2001, Catamount was in compliance with all covenants under the revolver except that Catamount's capital expenditures exceeded budget by an immaterial amount, which was waived by the lender in February 2002.

     In 1999, SmartEnergy Water Heating Services, Inc. ("SEWHS"), a wholly owned subsidiary of Eversant, secured a $1.5 million seven-year term loan with Bank of New Hampshire with an outstanding balance of $1.1 million at December 31, 2001. The interest rate is fixed at 9.5% per annum. Based on outstanding debt at December 31, 2001, the aggregate amount of SEWHS's long-term debt maturities are $0.2 million, $0.2 million, $0.2 million, $0.3 million and $0.2 million for the years 2002 through 2006, respectively. SEWHS's long-term debt contains financial and non-financial covenants. At December 31, 2001, SEWHS was in compliance with all debt covenants related to its various debt agreements.

Note 8
Short-term debt

     The Company had no short-term debt outstanding at December 31, 2001 or at December 31, 2000.

     The Company has an aggregate of $16.9 million of letters of credit which support three series of Industry Development/Pollution Control Bonds, with termination dates of May 31, 2002. The Company has begun the process of extending these letters of credit to August 31, 2003 with Citizens Bank of Massachusetts. These letters of credit are secured by a first mortgage lien on the same collateral supporting the Company's first mortgage bonds.

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Note 9
Financial instruments

     The estimated fair values of the Company's financial instruments at December 31, 2001 and 2000 are as follows (dollars in thousands):

	2001		2000
	Carrying   Amount	Fair   Value	Carrying   Amount	Fair   Value
Preferred stock not subject to    mandatory redemption	$  8,054	$  3,815	$  8,054	$  3,695
Preferred stock subject to    mandatory redemption	$16,000	$16,000	$16,000	$16,000
Long-term debt -
First mortgage bonds	$53,000	$52,259	$57,000	$58,381
Second mortgage bonds	$75,000	$76,163	$75,000	$74,432
Other long-term debt	$38,996	$38,996	$25,180	$25,180

     Cash and Cash Equivalents: The carrying amounts approximate fair value because of the short maturity of those instruments.

     Preferred stock and long-term debt: The fair value of the Company's fixed rate securities is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for the same remaining maturation. Adjustable rate securities are assumed to have a fair value equal to their carrying value.

     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
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 vested after completing five years of service, and can retire when they are at least age 55 with a minimum of 10 years of service, and are eligible to receive monthly benefits or a lump sum amount. The Company's funding policy is to contribute at least a statutory minimum to a trust. The Company is not required by its union contract to contribute to multi-employer plans.

     The Company elected to change the measurement date of pension obligations and related plan assets from December 31 to September 30 in 2000. This was not considered material enough to present in the Consolidated Statement of Income as a change in accounting principle.

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

	December 31
	2001	2000
Change in pension benefit obligation
Benefit obligation at beginning of year (January 1)	$  64,382	$  54,172
Service cost	2,138	1,901
Interest cost	5,046	4,614
Actuarial loss	3,699	5,952
Transfers	-	19
Benefits paid	(4,024)	(2,276)
Projected pension benefit obligation as of measurement date	$  71,241	$  64,382
Measurement date	September 30	September 30
	2001	2000
Change in pension plan assets
Fair value of plan assets (primarily equity and fixed income securities) at beginning of year (January 1)	$ 80,202	$ 79,834
Actual return on plan assets	(10,549)	2,625
Employer contribution	-	-
Transfers	-	19
Benefits paid	(4,024)	(2,276)
Fair value of pension plan assets (primarily equity   and fixed income securities) as of measurement date	$  65,629	$  80,202
Measurement date	September 30	September 30
	2001	2000
Reconciliation of funded status
Benefit obligation	$(71,241)	$(64,382)
Fair value of assets	65,629	80,202
Funded status	(5,612)	15,820
Unrecognized net transition asset	(437)	(582)
Unrecognized prior service cost	1,703	1,893
Unrecognized net actuarial gain	(4,942)	(26,211)
Accrued pension cost	(9,288)	(9,080)
FAS 71 regulatory asset (1997 VERP)	25	933
Effective (accrued) pension cost	$  (9,263)	$  (8,147)

	2001	2000	1999
Net pension costs include the following components
Service cost	$  2,138	$  1,901	$  1,854
Interest cost	5,046	4,614	4,035
Expected return on plan assets	(6,244)	(5,873)	(5,081)
Amortization of prior service cost	191	191	191
Recognized net actuarial gain	(776)	(550)	-
Amortization of transition asset	(146)	(146)	(146)
Supplemental adjustment for amortization of FAS 71   Regulatory asset (1994 VERP)	- -	- -	37
Supplemental adjustment for amortization of FAS 71   Regulatory asset (1997 VERP)	466	466	466
Accelerated amortization of FAS 71   Regulatory asset (1997 VERP)	441	-	-
Net periodic pension cost	1,116	603	1,356
Less amount allocated to other accounts	28	21	107
Net pension costs expensed	$  1,088	$    582	$  1,249

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     Assumptions used in calculating pension cost were as follows:

	December 31
	2001	2000
Weighted average discount rates	7.25%	7.75%
Expected long-term return on assets	8.50%	8.50%
Rate of increase in future compensation levels	4.50%	4.50%
Measurement date	September 30	September 30

     The Company sponsors a defined benefit postretirement medical plan that covers all employees who retire with 10 years or more of service and at least age 55. The Company funds this obligation through a Voluntary Employees' Benefit Association and 401(h) Subaccount in its pension plan.

     The Company elected to change the measurement date of postretirement medical plan obligations and related plan assets from December 31 to September 30 in 2000. This was not considered material enough to present in the Consolidated Statement of Income as a change in accounting principle.

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

	December 31
	2001	2000
Change in postretirement benefit obligation
Benefit obligation at beginning of year (January 1)	$  14,800	$  13,278
Service cost	243	183
Interest cost	1,114	984
Actuarial loss	2,874	1,058
Benefits paid	(2,949)	(703)
Projected postretirement benefit obligation as of   measurement date	$  16,082	$  14,800
Measurement date	September 30	September 30
	2001	2000
Change in postretirement plan assets
Fair value of plan assets (fixed income securities) at   beginning of year (January 1)	$    1,075	$    1,733
Actual return on plan assets	31	25
Employer contribution	2,752	20
Benefits paid	(2,949)	(703)
Fair value of postretirement plan assets (fixed income securities)   as of measurement date	$         909	$    1,075
Measurement date	September 30	September 30
	2001	2000
Reconciliation of funded status
Benefit obligation	$(16,082)	$(14,800)
Fair value of assets	909	1,075
Company contributions between measurement date and   fiscal year-end	3,584	906
Funded status	(11,589)	(12,819)
Unrecognized net transition obligation	2,814	3,070
Unrecognized net actuarial loss	6,003	3,193
Accrued postretirement benefit cost	(2,772)	(6,556)
FAS 71 regulatory asset (1997 VERP)	25	914
Effective (accrued) postretirement benefit cost	$   (2,747)	$   (5,642)

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	2001	2000	1999
Net postretirement benefit costs include the   following components
Service cost	$   243	$   183	$    214
Interest cost	1,114	984	892
Expected return on plan assets	(102)	(100)	(87)
Recognized net actuarial loss	135	51	93
Amortization of transition obligation	256	256	256
Supplemental adjustment for amortization of FAS 71   regulatory asset (1994 VERP)	- -	- -	37
Supplemental adjustment for amortization of FAS 71   regulatory asset (1997 VERP)	457	457	457
Accelerated amortization of FAS 71   regulatory asset (1997 VERP)	431	-	-
Net periodic benefit cost	2,534	1,831	1,862
Less amount allocated to other accounts	219	214	171
Net postretirement benefit costs expensed	$2,315	$1,617	$1,691

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

	December 31
	2001	2000
Per capita percent increase in health care costs:
Pre-65	11.00%	6.00%
Post-65	10.50%	5.50%
Weighted average discount rates	7.25%	7.75%
Rate of increase in future compensation levels	4.50%	4.50%
Long-term return on assets	8.50%	8.50%
Measurement date	September 30	September 30

     For measurement purposes, an 11% and 10.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for fiscal 2002, for pre-65 and post-65 claims costs, respectively. The rate is assumed to decrease 1% in each of the subsequent years until the ultimate trend of 6% and 5.5%, respectively, is reached.

     Increasing (decreasing) the assumed health care cost trend rates by one percentage point in each year would have resulted in an increase (decrease) of $828,890 and $(727,610), respectively, in the accumulated post-retirement benefit obligation as of December 31, 2001 and an increase (decrease) of about $68,397 and $(59,557), respectively, in the aggregate of the service cost and interest cost components of net periodic post-retirement benefit cost for 2001.

     The Company provides postemployment benefits consisting of long-term disability benefits. The accumulated postemployment benefit obligation at December 31, 2001 and 2000 of $1.1 million and $1.1 million, respectively, is reflected in the accompanying Consolidated Balance Sheets as a liability and in 2000 was offset by a corresponding regulatory asset of $0.2 million. Pursuant to an October 1994 PSB Rate Order, the Company was allowed to recover the regulatory asset over a 7-1/2 year period beginning November 1, 1994 through April 30, 2002. In mid 2001, $0.1 million of the regulatory asset was written off as a result of the Company's June 26, 2001 approved rate order. The pre-tax postemployment benefit costs charged to expense in 2001, 2000 and 1999, including insurance premiums, were $271,000, $481,000, and $281,000 respectively.

     In the third quarter of 1997, the Company offered and recorded obligations related to a voluntary retirement and severance program to employees. The estimated benefit obligation for the retirement program as of December 31, 2001 is approximately $0.1 million. This amount consists of pension benefits and postretirement medical benefits. These obligations, deferred pursuant to a PSB Accounting Order dated September 30, 1997, are reflected in the accompanying Consolidated Balance Sheets both as regulatory assets and deferred credits. The unamortized balance of approximately $0.1 million at December 31, 2001 will be amortized through December 31, 2002. The majority of the regulatory asset related to the 7-1/2 year transitional obligation was written off as a result of the June 26, 2001 approved rate order. See Notes 1 and 12 related to Regulatory Assets and Retail Rates, respectively, for additional information.

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Note 11
Income taxes

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

	Year Ended December 31
	2001	2000	1999
Federal:
Current	$10,625	$12,195	$  6,760
Deferred	(3,713)	(2,542)	1,587
Investment tax credits, net	(391)	(391)	(391)
	6,521	9,262	7,956
State:
Current	2,976	3,440	1,664
Deferred	(1,113)	(891)	775
	1,863	2,549	2,439
Total federal and state income taxes	$8,384	$11,811	$10,395
Federal and state income taxes charged to:
Operating expenses	$ 11,472	$  9,034	$10,360
Other income	(2,964)	2,777	35
Extraordinary loss	(124)	-	-
	$ 8,384	$11,811	$10,395

     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
	2001	2000	1999
Income before income tax	$10,791	$29,854	$26,979
Federal statutory rate	35%	35%	35%
Federal statutory tax expense	3,777	10,449	9,443
Increases (reductions) in taxes  Resulting from:
Dividend received deduction	(741)	(895)	(790)
Deferred taxes on plant	147	453	453
State income taxes net of federal tax benefit	1,203	1,735	1,568
Investment credit amortization	(391)	(391)	(391)
AFDC Equity	214	209	139
Valuation Allowance	3,985	-	-
Other	190	251	(27)
Total income tax expense provided	$8,384	$11,811	$10,395

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

	Year Ended December 31
	2001	2000	1999
Deferred tax assets
Purchased power accrual	$        -	$   1,213	$  1,603
Loss credit carryforwards	6,513	-	-
Accruals and other reserves not    currently deductible	2,150	7,833	6,668
Retiree medical benefits	1,465	-	-
Deferred compensation and pension	5,679	5,587	5,402
Environmental costs accrual	3,811	3,928	4,249
Valuation Allowance	(3,985)
Total deferred tax assets	15,633	18,561	17,922
Deferred tax liabilities
Property, plant and equipment	47,518	50,359	50,164
Net regulatory asset	2,777	2,913	3,485
Conservation and load     management expenditures	1,890	4,222	5,445
Nuclear refueling costs	1,076	797	3,313
Other	1,200	4,049	4,146
Total deferred tax liabilities	54,461	62,340	66,553
Net deferred tax liability	$38,828	$43,779	$48,631

     The Company received an accounting order from the PSB dated September 30, 1997, authorizing 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 been recorded in the amount of $4.0 million to reflect Management's best estimate of loss credit carryforwards that will ultimately be utilized. All other deferred income tax assets are expected to be realized.

Note 12
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

     1997 Retail Rate Case: 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.

     In response to the Company's September 1997 rate increase 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 argued its posi tion before the Vermont Supreme Court.

     1998 Retail Rate Case: On June 12, 1998, the Company filed with the PSB for a 10.7% retail rate increase that supplanted the September 22, 1997 rate increase request of 6.6%, 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

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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 was subject to retroactive or prospective adjustment upon future resolution of issues arising under the Hydro-Quebec and Vermont Joint Owner's ("VJO") Power Contract. The agreement temporarily disallowed approximately $7.4 million (based on 1999 power costs) for the Company's purchased power costs under the VJO Power Contract. As a result of the 4.7% rate increase agreement, during the fourth quarters of 1998 and 1999, the Company recorded pre-tax losses of $7.4 million and $2.9 million, respectively, 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 1999 and the first quarter of 2000, respectively. In 2000, an additional $11.5 million pre-tax loss was recorded for the estimated under-recovery of Hydro-Quebec power costs for the second, third and fourth quarters of 2000, and the first quarter of 2001. In the first quarter of 2001, an additional $2.9 million pre-tax loss was recorded for the estimated under-recovery of Hydro-Quebec power costs for the second quarter of 2001. In the second quarter of 2001, the Company reversed its $2.9 million pre-tax liability related to estimated under-recovery of Hydro-Quebec power costs and discontinued the accrual based on the favorable outcome of the Company's June 26, 2001 rate order, which is described below.

     2000 Retail Rate Case: In an effort to mitigate eroding earnings and cash flow prospects in the future, due mainly to under-recovery of power costs, on November 9, 2000, the Company filed with the PSB a request for a 7.6% rate increase ($19.0 million of annualized revenues) effective July 24, 2001. The PSB suspended the rate filing and a schedule was set to review the case.

     On February 9, 2001, the Vermont Supreme Court issued a decision on the Company's 1998 rate case appeal that reversed the PSB's decision on the preclusion issues and remanded the case to the PSB for further proceedings consistent with the Vermont Supreme Court's decision.

     The Company's June 26, 2001 rate order, which is described below, ended the uncertainty over the future recovery of Hydro-Quebec contract costs and the Company will no longer incur future losses for under-recovery of Hydro-Quebec contract costs related to any allegations of imprudence prior to the June 26, 2001 rate order.

     On May 7, 2001, the Company and the DPS reached a rate case settlement that would end uncertainty over the future recovery of Hydro-Quebec contract costs, allow a 3.95 % rate increase, make the January 1, 1999 temporary rates permanent, permit a return on equity of 11% for the twelve months ending June 30, 2002 for the Vermont utility, and create new service quality standards. The Company also agreed to a second quarter $9.0 million one-time write-off ($5.3 million after-tax) of regulatory assets and a rate freeze through January 1, 2003.

     On June 26, 2001, the PSB issued an order on the Company's rate case settlement with the DPS. In addition to the provisions outlined above, the approved rate order requires the Company to return up to $16.0 million to ratepayers in the event of a merger, acquisition or asset sale if such sale requires PSB approval. As a result of the rate order, the 3.95% rate increase became effective with bills rendered July 1, 2001, and in June 2001 the Company recorded a $5.3 million after-tax loss to write off certain regulatory assets as agreed to in the settlement. The Company was able to accept the 3.95% rate increase versus the 7.6% increase it requested since 1) regulatory asset amortizations will decrease approximately $3.5 million, on a twelve-month basis, due to the $9.0 million one-time write-off of regulatory assets and 2) Vermont Yankee decommissioning costs decreased approximately $1.9 million, on a twelve-month basis, after the rate case was filed as a result of an agreem ent in principle between Vermont Yankee and the secondary purchasers.

     Deseasonalized Rates: On June 8, 2000, the PSB approved the Company's request to end the winter-summer rate differential and, therefore, the Company now has flat rates throughout a given year. Winter rates were reduced by 14.9%, while summer rates were increased by 10.5%. The rate design change was revenue neutral over a twelve-month period. The additional revenues in 2000, resulting from implementing this change in mid-year, were applied to reduce regulatory deferrals related to the Hydro-Quebec ice storm arbitration, as directed by the PSB.

New Hampshire Retail Rate/Federal Court Proceedings

     Connecticut Valley's retail rate tariffs, approved by the NHPUC, contain a Fuel Adjustment Clause ("FAC") and a Purchased Power Costs 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.

     In 1998, management determined that Connecticut Valley no longer qualified for the application of SFAS No. 71, and wrote off all of its regulatory assets associated with its New Hampshire retail business totaling approximately $1.3 million on a pre-tax basis. This determination was based on various legal and regulatory actions

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including the February 28, 1997 NHPUC Final Plan to restructure the electric utility industry in New Hampshire, a supplemental order that required Connecticut Valley to give notice to cancel its power contract with the Company and denied stranded cost recovery related to this power contract, and a December 3, 1998 Court of Appeals decision stating that Connecticut Valley's rates could be reduced to the level prevailing on December 31, 1997. The Company's petition for rehearing with the Court of Appeals as well as petition for writ of certiorari with the United States Supreme Court were subsequently denied.

     As a result of the December 3, 1998 Court of Appeals decision, on March 22, 1999 the NHPUC issued an Order that directed Connecticut Valley to file 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. 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. On March 26, 1999, Connecticut Valley filed the required tariff page with the NHPUC, under protest and with reservation of all rights, and implemented the refund effective April 1, 1999.

     On April 7, 1999, the Federal District Court ("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. The Court's decision was issued as a written order on May 11, 1999.

     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 contended, among other things, that it is unfair for the NHPUC to direct Connecticut Valley to continue to purchase wholesale power from the Company 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 these power costs.

     On June 14, 1999, Public Service Company of New Hampshire ("PSNH") and various parties in New Hampshire announced that a "Memorandum of Understanding" had been reached which was 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 related to electric utility restructuring in New Hampshire indefinitely while the proposed settlement was 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.

     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. Accordingly, during the fourth quarter of 1999, Connecticut Valley recorded a pre-tax loss of $1.2 million for under-collection of year 2000 power 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 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."

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     On March 6, 2000, the Court granted summary judgement to Connecticut Valley and the Company on their claim under the filed-rate doctrine and issued a permanent injunction mandating that the NHPUC allow Connecticut Valley to pass through to its retail customers its wholesale costs incurred under the rate schedule with the Company. The Court also ruled that Connecticut Valley was entitled to recover the wholesale costs that the NHPUC disallowed in retail rates since January 1, 1997.

     Pursuant to the March 6, 2000 Court Order, on March 17, 2000, Connecticut Valley filed a rate request with the NHPUC for an Interim FAC/PPCA to recover the balance of wholesale costs not recovered since January 1997. To mitigate the rate increase percentage, the Interim FAC/PPCA was designed to recover current power costs and a substantial portion of past under-collections by the end of 2000; the remainder of the past under-collections were being collected during 2001 along with 2001 power costs. The NHPUC held a hearing on April 7, 2000 to review the 12.3% increase that would raise $1.6 million of revenues in 2000. The NHPUC issued an order approving the rates as temporary effective May 1, 2000.

     On July 25, 2000, the Court of Appeals affirmed the Court's March 6, 2000 Order granting summary judgement to Connecticut Valley and the Company. The NHPUC then asked the Court of Appeals to reconsider its decision. That request was denied. As a result of the favorable Court of Appeals action, Connecticut Valley recorded a $2.0 million after-tax gain in the third quarter of 2000. On November 27, 2000, the NHPUC filed a petition for writ of certiorari with the United States Supreme Court. On February 20, 2001, the Supreme Court denied the petition for writ of certiorari, thus leaving the Court of Appeals approval of the permanent injunction intact.

     In the third quarter of 2001, Management determined that Connecticut Valley is again subject to cost-based ratemaking and qualifies for the application of SFAS No. 71. This decision was based on the favorable Court of Appeals decision of July 25, 2000 and the subsequent denial of the NHPUC's petition for writ of certiorari by the United States Supreme Court on February 20, 2001 as well as other regulatory developments in New Hampshire during 2001. The application of SFAS No. 71 resulted in an extraordinary charge of $0.2 million for Connecticut Valley.

     As part of its restructuring plan, the New Hampshire Legislature enacted an Electricity Consumption Tax on customers and repealed the New Hampshire Franchise Tax on utilities, both of which became effective May 1, 2001. Since the Franchise Tax, as a credit to the New Hampshire Business Profits Tax, was larger than the Business Profits Tax, the repeal of the Franchise Tax caused Connecticut Valley to incur the Business Profits Tax. The NHPUC approved a settlement that reduced base rates to remove recovery of the Franchise Tax and implemented a Business Profits Tax Percentage Adjustment that would be subject to annual revisions in order to collect the Business Profits Tax.

     On December 31, 2001, the NHPUC ruled on Connecticut Valley's request for a Temporary Billing Surcharge to recover approximately $1.7 million of one-time costs primarily related to industry restructuring effective January 1, 2002. Connecticut Valley had proposed the Temporary Billing Surcharge to exactly offset a contemporaneously filed FAC/PPCA decrease of 9.3% such that a zero rate change would occur at January 1, 2002 and the 9.3% FAC/PPCA decrease would occur when the Temporary Billing Surcharge terminated in November 2002. The NHPUC affirmed its prior policy of considering recovery of costs related to industry restructuring at the time retail choice is implemented in the Connecticut Valley service area. Thus the NHPUC deferred action on all but $125,000, for which recovery was allowed through November 30, 2002.

     On December 31, 2001 the NHPUC approved Connecticut Valley's FAC and PPCA rates for 2002 as well as Connecticut Valley's Business Profits Tax Adjustment Percentage and Conservation and Load Management Percentage Adjustment for 2002. Combined with the Temporary Billing Surcharge, the result was an overall 8.6% rate reduction with a revenue decrease of $1.8 million.

FERC Proceedings

     On February 28, 1997, Connecticut Valley was directed by the NHPUC to terminate its purchase of power from the Company. 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 the notice of cancellation of that rate schedule (contingent upon the recovery of the stranded costs that would result from the cancellation of that rate schedule). In December 1997, the FERC rejected the Company's proposal to recover stranded costs through the imposition of a surcharge in the Company's transmission tariff, but indicated that it would consider an exit fee mechanism in the wholesale rate schedule for collecting stranded costs. The FERC denied the Company's motion for a rehearing regarding the transmission surcharge proposal. However, the Company filed a request with the FERC for an exit fee mechanism in the wholesale rate schedule to collect the stranded costs resulting from the

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cancellation of the wholesale rate schedule. The stranded cost obligation sought to be recovered was $90.6 million in nominal dollars and $44.9 million on a net present value basis as of December 31, 1997.

     On April 24, 2001, a FERC Administrative Law Judge ("ALJ") issued an Initial Decision in the Company's stranded cost/exit fee proceeding. The ALJ ruled that if Connecticut Valley terminates its relationship as a wholesale customer of the Company and subsequently becomes a wholesale transmission customer of the Company, Connecticut Valley shall be liable for payment of stranded costs to the Company. The ALJ calculated, on an illustrative pro-forma basis, a nominal stranded cost obligation of nearly $83.0 million through 2016. The amount of the exit fee as determined by the ALJ will decrease with each year that service continues and normal tariff revenues are collected, and will ultimately be calculated from the date of termination, if notice of termination is ever given. Absent termination of the wholesale rate schedule by mutual agreement, the earliest termination date that could presently occur pursuant to the wholesale rate schedule is December 31, 2003. The stranded c ost obligation as of December 31, 2003, expressed on a net present value basis set forth in the ALJ order, is approximately $33.9 million.

     The ALJ's Initial Decision is subject to review and approval by the FERC. If the Company is unable to obtain approval by the FERC, and if Connecticut Valley is forced to terminate its relationship as a wholesale customer of the Company, it is possible that the Company would be required to recognize a pre-tax loss under this contract totaling approximately $32.9 million as of December 31, 2003. The Company would also be required to write-off approximately $0.9 million (pre-tax) of regulatory assets associated with its wholesale business as of December 31, 2003. If the Company obtains a FERC order authorizing the updated requested exit fee and notice of termination is given, Connecticut Valley will apply to the NHPUC to increase rates in order to pay the exit fee. The Company believes that the NHPUC must permit Connecticut Valley to raise rates to recover the cost of the exit fee. However, if Connecticut Valley is unable to recover its costs in rates, Connecticut Valley w ould be required to recognize the loss discussed above.

     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.

     An adverse resolution of the FERC and New Hampshire 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. See New Hampshire Retail Rates/Federal Court Proceedings above for additional information.

Wheelabrator Power Contract

     Connecticut Valley purchases power from several Independent Power Producers, who own qualifying facilities as defined by the Public Utility Regulatory Policies Act of 1978. In 2001, under long-term contracts with these qualifying facilities, Connecticut Valley purchased 38,890 mWh, of which 96% was purchased from Wheelabrator Claremont Company, L.P., ("Wheelabrator") who owns a waste-to-energy electric generating facility. Connecticut Valley had filed a complaint with the FERC stating its concern that Wheelabrator has not been a qualifying facility since the facility began operation. On February 11, 1998, the FERC issued an Order denying Connecticut Valley's request for a refund of past purchased power costs and lower future costs. Connecticut Valley filed a request for rehearing with the FERC on March 13, 1998, which was denied. Connecticut Valley appealed to the D.C. Circuit Court of Appeals, which denied the appeal, but indicated that Connecticut Valley could seek relief from the NHPUC. On May 12, 2000, Connecticut Valley filed a petition with the NHPUC seeking 1) to amend the contract to permit purchase of net, rather than gross, output of the facility and 2) a refund, with interest, of past purchases of the difference between net and gross output.

     In December 2000 and January 2001, Wheelabrator, the New Hampshire/Vermont Solid Waste District, and several Connecticut Valley residential customers filed with the NHPUC to intervene. The Office of Consumer Advocate and the NHPUC Staff are automatic parties. A Prehearing Conference was held before the NHPUC on January 4, 2001, at which time each party provided preliminary position statements with regard to the petition. In February and March 2001, the parties filed briefs on the legal issues and Wheelabrator filed a motion to dismiss. The Company cannot predict when the NHPUC will issue a decision on the legal issues or the motion to dismiss or on the outcome of this matter.

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Note 13
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.

Nuclear Investments The Company has investments in, and is entitled to receive power from, four nuclear generating companies, three of which (Maine Yankee, Connecticut Yankee and Yankee Atomic) are permanently shut down. 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 Millstone Unit #3 nuclear generating plant. In August 2000, the Company received a cash settlement of $5.4 million pursuant to a July 27, 2000 settlement agreement with NU resolving all issues related to arbitration and lawsuits sought to recover costs associated with the shutdown of Unit #3 in 1996. On September 15, 1999, NU announced its intent to auction its nuclear generating plants, including Unit #3. On August 7, 2000, the Connecticut Department of Public Utility Control announced that Dominion Resources, Inc. was the successful bidder in the auction. Pursuant to the terms of the settlement agreement described abov e, the Company participated as a potential seller in that auction. Upon notification of the sales price, the Company evaluated and declined the purchase offer. The sale to Dominion Nuclear Connecticut ("DNC"), a subsidiary of Dominion Resources, became final on March 31, 2001.

Independent Power Producers ("IPPs") 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 2001, the Company received 168,382 mWh of which 118,187 mWh is associated with the Vermont Electric Power Producers and 37,293 mWh with Wheelabrator. The Company expects to purchase approximately 197,000 mWh of independent power output in each year 2002 through 2006. 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 $116 million, which excludes the impact of the January 28, 2002 Memorandum of Understanding described below.

     On August 3, 1999, the Company, 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 outlined seven specific elements that, if implemented, would reduce purchase power costs and reform these contracts for the benefit of consumers. On September 3, 1999, the PSB opened a formal investigation in Docket No. 6270 regarding these contracts as requested by the Petition. Shortly thereafter, Citizens Utilities, Hardwick Electric Department and Burlington Electric Department notified the PSB that they were withdrawing from the Petition but would participate in the case as non-moving parties. In a separate action before the Chittenden County Superior Court brought by several IPP owners, GMP's full participation in this PSB proceeding was enjoined and that injunction has since been appealed to and affirmed by the Vermont Supreme Court. The Company, the other moving utilities and the DPS requested that the PSB issue an order requiring GMP's full participation in the PSB proceeding. The PSB declined to rule on the request but retained authority to require GMP to provide specific information or to submit any other specific filing.

     On November 22, 2000, the IPPs' filed dispositive motions in Docket No. 6270, urging the PSB to declare that it lacks jurisdiction to grant relief sought by the Company's Petition. On January 8, 2001, the Company and the other petitioning utilities filed responses to the IPP's motions, supporting the PSB's exercise of jurisdiction, as called under the Petition. The DPS also made a filing in support of jurisdiction. On June 1, 2001, the PSB Hearing Officer issued a Proposal for Decision ("PFD") on the PSB's jurisdiction to consider the Petition. The PFD recommended that the PSB find that it has jurisdiction to consider the relief sought under the Petition but that the PSB may be precluded from issuing orders reducing the lengths of a Purchasing Agent contract or requiring buy-outs or buy-downs. Docket participants filed comments on the PFD. On September 18, 2001, the PSB issued an Order regarding jurisdiction in which it adopted the conclusions of the Hearing Officer's P FD and found that it has jurisdiction to consider five of the seven claims outlined in the original Petition.

     The IPPs 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." By motion filed in the Superior Court in September 2000, the IPPs sought summary judgement in this action. On January 19, 2001, the Washington County Superior Court dismissed the IPPs' action, which the

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IPPs appealed to the Vermont Supreme Court. The IPPs also asked the Vermont Supreme Court to stay the proceeding before the PSB pending the outcome of their appeal. By order dated April 5, 2001, the Vermont Supreme Court denied the IPPs' request for a stay.

     On March 15, 2001, the IPPs also filed a related complaint before the FERC, requesting that the FERC issue an order preventing the Company and the other Vermont utilities from employing FERC Order No. 888 to require the IPPs, either directly or indirectly, to reserve transmission service and pay transmission charges in connection with their power sales. In principal part the IPPs argue that such reservations and related charges are prohibited under the regulations adopted by the State of Vermont to implement the Public Utilities Regulatory Policies Act of 1978. On April 4, 2001, the Company and other Vermont utilities filed their response arguing that the IPP complaint should be dismissed on procedural grounds and opposing the IPPs' allegations on the merits. By Order dated May 16, 2001, the Commission declined to grant the relief requested and instead found that the complaint was premature in light of the fact that the PSB has yet to rule on the disputed issues in the pro ceeding open before it to consider the Petition.

     In September 2001, the Petitioners and the IPPs agreed to enter into a settlement discussion and on September 28, 2001 filed a Stipulation for Stay requesting that further proceedings in the Docket be stayed to provide the parties an opportunity to engage in settlement negotiations. A similar motion was also filed with the Vermont Supreme Court regarding the appeal on the so-called "scrivener's error" case. On October 18, 2001, the PSB Hearing Officer issued an order granting the Stipulation for Stay and indicated that a status conference would be convened midway through the 90-day period, which was due to expire January 4, 2002. A status conference on the parties' settlement efforts was convened on November 27, 2001.

     After several extensions, on January 28, 2002, the Petitioners and the IPPs filed a Memorandum of Understanding with the PSB which, if approved, establishes a comprehensive settlement to the issues in Docket No. 6270. The Memorandum of Understanding would provide:

1. power cost reductions nominally worth approximately $11.0 million to $14.0 million over ten years;
2. the agreement of the IPPs to support efforts before the Vermont General Assembly and the PSB to authorize securitization and to negotiate for the buy-out and buy-down of the IPP contracts with the goal of achieving additional power cost savings; and
3. a global resolution of various related issues.

     At this time, proceedings are continuing in PSB Docket No. 6270 to consider the Memorandum of Understanding. A status conference on the matter was held in February 2002. A decision in this matter is expected in 2002.

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

     The average annual amount of capacity that the Company will purchase from January 1, 2002 through October 31, 2012 is 143 mW, with lesser amounts purchased through October 31, 2016. The Company's total commitment to purchase power under these contracts on a nominal basis is approximately $877 million over the contract term. In February 1996, the Company reached an agreement with Hydro-Quebec that lowered the 1997 cost of power by $5.8 million. As part of this agreement, the Company made 54 mW of Phase I/II capacity available to Hydro-Quebec for its use to deliver an existing Firm Energy Contract or jointly marketed energy contracts to buyers in NEPOOL during the period from July 1, 1996 through June 30, 2001.

     In the early phase of the VJO Power 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 through 1996. In 1994, the Company negotiated a third sellback arrangement whereby the Company received 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 upon four years written notice, to reduce capacity deliveries by up to 50 mW beginning as early as 2007 until 2015. This option includes the use of a like amount of the Company's Phase I/II facility rights. Hydro-Quebec also can exercise an option, upon one years written notice, to curtail energy deliveries from an annual load factor of 75% to 50% due to adverse hydraulic conditions in Quebec. This can be exercised five times between November 2000 and October 2015. Additionally, the VJO can elect to change the annual load factor from 75% to between 70% and 80% five times through 2020, while Hydro-Quebec can elect to reduce the load factor to not less than 65% three times during

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the same period of time (the VJO contract runs through 2020, however, the Company's schedules related to the contract end in 2016). The VJO has made three out of five elections to date, while Hydro-Quebec made its first election for the contract year beginning November 1, 2001 and the VJO has since elected to push the start of the 65% load factor to November 1, 2002. The Company does not expect this change in load factor to have a significant financial impact.

     There are specific contractual 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, 2001, the Company's obligation is approximately 46% of the total VJO Power Contract through 2016. The projected total VJO contract obligation on a nominal basis over the term of the contract (2020) is approximately $1.9 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 had been and remained unable to make available capacity with the degree of firmness required by the VJO Power Contract. That determination prompted the VJO to initiate an arbitration proceeding. In the arbitration, the VJO was seeking to terminate the contract, to recover damages associated with Hydro-Quebec's failure to comply with the contract, and t o 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 were held in the second and third quarters of 2000. On April 17, 2001, the Company received a decision in the arbitration proceeding relating to the failure by Hydro-Quebec to deliver power during the outage in 1998. The decision stated that the long-term power supply contract between Hydro-Quebec and the Vermont utilities remains in effect, that Hydro-Quebec is required to reimburse the Vermont utilities for capacity payments made during the outage for power not delivered and ordered a refund to the VJO, valued at up to approximately $20.0 million plus interest, which amount would be adjusted downward to reflect either actual deliveries by Hydro-Quebec in the first quarter of 1998 or an agreement by the parties.

     In accordance with a PSB Accounting Order, the Company deferred legal, consulting and related costs associated with this arbitration of approximately $6.4 million at September 30, 2001. These deferred costs were offset by incremental revenue of $3.8 million, resulting from the implementation of deseasonalized rates on July 1, 2000 through December 31, 2000, as directed by the PSB. As part of the Company's June 26, 2001 rate order, the Company agreed that all amounts collected based on the award issued by the arbitration panel, or any settlement agreement with Hydro-Quebec or any other party related to the Company's VJO contract power supply costs, shall be applied first to reduce the remaining balance of deferred costs related to the ice storm arbitration, with the remaining balance, if any, applied to reduce other regulatory asset accounts as specified by the DPS and approved by the PSB.

     On July 19, 2001, Hydro-Quebec and the VJO agreed to a final settlement of the arbitration issues. Under the settlement, the VJO will continue to receive power and energy from Hydro-Quebec under this contract through 2016. As part of the settlement, Hydro-Quebec made a $9.0 million payment to the VJO in July 2001, of which the Company's share was approximately $4.3 million. In the third quarter of 2001, the Company applied approximately $2.7 million to the remaining balance of the deferred costs related to the ice storm arbitration. On October 30, 2001, the Company filed a letter with the PSB summarizing its agreement with the DPS on application of the remaining $1.6 million of the Hydro-Quebec settlement to remaining regulatory assets, which agreement is subject to approval by the PSB. Currently, the remaining $1.6 million balance is included as a deferred credit on the Company's Consolidated Balance Sheet.

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

	Fuel Type	Ownership	In Service Date	mW Entitlement	December 31 2001               2000
Generating plants:
Wyman #4	Oil	1.78%	1978	11.0	$  3,347	$  3,347
Joseph C. McNeil	Various	20.00%	1984	10.6	15,365	15,273
Millstone Unit #3	Nuclear	1.73%	1986	20.0	76,143	75,873
Highgate Transmission Facility		47.35%	1985	N/A	14,086	14,052
					108,941	108,545
Accumulated depreciation					47,049	44,146
					$ 61,892	$ 64,399

     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.

     The Company remained an owner of the Millstone Unit #3 facility when DNC became the lead owner with approximately 93.47% of the plant joint-ownership. As part of the regulatory approvals of the sales to DNC by the joint owners of that plant, DNC has represented to the Nuclear Regulatory Commission ("NRC") and other regulatory bodies, including the Connecticut Department of Public Utility Control, that the Millstone Unit #3 Decommissioning Trust Fund, for its share of the plant, exceeds the NRC minimum calculation required and therefore no further contributions to the fund are required at this time. The Company has agreed with the DPS position in its recent rate case that the DNC representation that contributions currently can cease is appropriate subject to periodic review of both the fund balance and the NRC minimum calculation upon which the DNC bases its assertion of fund adequacy. The Company could choose to renew funding at its own discretion as long as the minimum re quirement is met or exceeded.

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 four different locations. The Company discontinued these activities in the late 1940s or early 1950s. 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 past 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.

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Cleveland Avenue Property The Company's Cleveland Avenue property, located in the City of Rutland, Vermont, was 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 1980s and early 1990s 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 of Vermont in a joint effort to develop a mutu ally acceptable solution.

Brattleboro Manufactured Gas Facility From the early to late 1940s, the Company owned and operated a manufactured gas facility in Brattleboro, Vermont. The Company commissioned an environmental site assessment in late 1999 upon request by the State of New Hampshire. In April 2000, the Company presented the assessment findings to the States of New Hampshire and Vermont and the Town of Brattleboro. The State of Vermont concluded that additional semi-annual site monitoring is necessary and that the Company must develop a corrective action plan. The State of New Hampshire required additional work to validate certain findings and conclusions made by the Company's consultant after completing its initial investigation in 1999.

     In early 2001, the Company submitted a work plan to the State of New Hampshire to address their concerns and in October 2001 the Company received a Certificate of No Further Action from the State of New Hampshire; however, the State reserves the right to require additional investigation or remedial measures, if necessary. In the third quarter of 2001, the Company submitted a corrective action plan to the State of Vermont. On January 17, 2002, the Company received a letter from the Vermont Agency of Natural Resources notifying the Company that its corrective action plan for the site is approved. The Company will now proceed with implementation of the corrective action plan, which includes provisions for periodic groundwater monitoring and institutional controls.

Dover, New Hampshire, Manufactured Gas Facility In late 1999, the Company was contacted by PSNH with respect to this site. PSNH alleged 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 and PSNH agreed to and have already participated in a non-binding mediation to further investigate the terms and conditions surrounding the sale of the plant to PSNH and Twin State's merger into the Company.

     In December 2000, PSNH submitted a work plan to the State of New Hampshire for further investigation of this site. The Company agreed, with reservations, to participate on a limited basis in the development and completion of the work plan since the State of New Hampshire considers the Company, along with others, as potentially responsible parties at the site. The Company, PSNH and Keyspan Energy hired a contractor, which completed the fieldwork in October 2001. A report will be published and submitted to the State of New Hampshire in early 2002. Shortly thereafter, the Company and others will begin evaluating remediation options for the site.

     Having previously agreed to non-binding mediation, a mediator on the issue of liability was chosen in April 2001 and the first phase of mediation, or "Phase I", concluded on July 18, 2001. Without admitting liability, both the Company and PSNH agreed to participate in the site remediation for those years that Twin State and PSNH were responsible. On October 30 and 31, 2001, the Company and PSNH met with others in a "Phase II" mediation process. The subject of the Phase II mediation was the liability of other potentially responsible parties at the site, in particular those that owned the property after Twin State and PSNH. The Phase II mediation process did not achieve the goal of a general agreement on liability between the participants.

     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 any other federal or state agency sought contribution from the Company for the study or remediation of any such sites.

     As of December 31, 2001, a reserve of $9.2 million has been established representing management's best estimate of the costs to remediate the sites discussed above.

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 $90.2 million of retained earnings was not subject to dividend restriction at December 31, 2001.

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     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 $19.4 million of retained earnings would not be subject to dividend restrictions at December 31, 2001.

     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 interconnection 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 4.55% 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 New England participants, including the Company, have contracted to pay their proportionate share of the total cost of constructing, owning and operating the Phase II facilities, including capital costs. 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. These support agreements meet the capital lease accounting requirements under SFAS No. 13, "Accounting for Leases". All costs under these support agreements are recorded as purchased transmission expense in accordance with the Company's ratemaking policies. Future expected payments will range and decline from approximately $4.0 million to $3.0 million for each year from 2002 through 2015 and will decline thereafter.

     The Company's shares of the net capital cost of these facilities, totaling approximately $14.0 million, are classified in the accompanying Consolidated Balance Sheets 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, 2001, 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 $4.2 million each year for 1999, 2000 and 2001.

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

Change of control The Company has management continuity agreements with certain Officers that become operative upon a change in control of the Company. Potential severance expense under the agreements varies over time depending on several factors, including the specific plan for individual officers and officers' compensation and age at the time of the change of control.

Note 14
Recent accounting pronouncements

Derivative Instruments: On January 1, 2001, the Company adopted SFAS No. 133 (subsequently amended by SFAS No. 137 and 138), Accounting for Derivative Instruments and Hedging Activities ("SFAS No. 133"). This Statement, as amended, establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. The 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.

     The Company has one long-term purchase power contract that allows the seller to purchase specified amounts of power with advance notice (Hydro-Quebec Sellback #3). This contract has been determined to be a derivative under SFAS No. 133. On April 11, 2001, the PSB approved an Accounting Order that allows the fair valuation adjustment of this contract to be deferred on the balance sheet as either a deferred asset or liability. At December 31, 2001, this

derivative had an estimated fair market value of approximately a $1.0 million unrealized loss, which is included in

Page 76 of 100

Other deferred credits on the Consolidated Balance Sheet along with an offsetting deferred asset which is included in Other deferred charges.

Goodwill and Other Intangible Assets: In July 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 142, Goodwill and Other Intangible Assets ("SFAS No. 142"), effective for fiscal years beginning after December 15, 2001. SFAS No. 142 establishes a new accounting standard for the treatment of goodwill. The new standard continues to require recognition of goodwill as an asset in a business combination but does not permit amortization as is done under current accounting standards. Effective January 1, 2002, SFAS No. 142 requires that goodwill be separately tested for impairment using a fair-value based approach as opposed to the undiscounted cash flow approach used under current accounting standards. If goodwill is found to be impaired, the Company would be required to record a non-cash charge against income, which would be recorded as a cumulative effect of a change in accounting principle. The impairment charge would be equal to the amount by which the carrying amount of the goodwill exceeds its estimated fair value. The Company has no goodwill related to it's regulated businesses, however, Catamount has goodwill of approximately $2.0 million related to three of its investments, but does not expect an impairment resulting from the implementation of SFAS No. 142.

Asset Retirement Obligations: In August 2001, the FASB approved the issuance of SFAS No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143"). This statement provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of long-lived assets and requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The Company has identified potential retirement obligations associated with the decommissioning of its nuclear facilities, but has not yet completed its assessment. This statement is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Company has not yet quantified the impacts, if any, of adopting SFAS No. 143 on its financial statements.

Impairment or Disposal of Long-Lived Assets: In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS No. 144") which replaces SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. This statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. Although SFAS No. 144 supercedes SFAS No. 121, it retains the fundamental provisions of SFAS No. 121 regarding recognition/measurement of impairment of long-lived assets to be held and used and measurement of long-lived assets to be disposed of by sale. Under SFAS No. 144, asset write-downs from discontinuing a business segment will be treated the same as other assets held for sale. The new standard also broadens the financial statement presentation of discontinued operations to include the disposal of an asset group (rather than a segment of a business). SFAS No. 144 is effec tive beginning January 1, 2002 and, generally, is to be applied prospectively. The Company does not expect that SFAS No. 144 will have a significant impact on its financial position or results of operations.

Note 15
Segment reporting

     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 Energy Corporation ("Catamount"), which has investments in non-regulated, energy-supply projects in North America and Western Europe; and Eversant Corporation ("Eversant"), which pursues retail alliances to market energy and related products and services, engages in the sale of or rental of electric water heaters to customers in Vermont and New Hampshire and as of December 31, 2001, had a 13.4% ownership interest, on a fully diluted basis, in the Home Services Store ("HSS"), operating nationwide. On October 23, 2001, SmartEnergy Services, Inc. changed its name to Eversant Corporation. CVEC, while managed on an integrated basis with CV, is pres ented 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. Certain information for 2000 and 1999 has been restated for the separate reporting of equity income - non-utility affiliates.

     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 Eversant.

Page 77 of 100

     The 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. Financial information by industry segment for 2001, 2000 and 1999 is as follows (dollars in thousands):

					Reclassification
	CV	CVEC			and Consolidating
	VT	NH	Catamount	Eversant	Other(1)	Entries	Consolidated
2001
Revenues from external customers	$281,745	$  20,738	$    504	$   2,397	$      7	$   2,915	$302,476
Intersegment revenues	11,297	-	-	-	-	11,297	-
Depreciation and other (2)	15,458	475	57	315	3	375	15,933
Regulatory asset write-off (6)	9,000	-	-	-	-	-	9,000
Reversal of estimated loss on power contracts (3)	2,934	-	-	-	-	-	2,934
Asset impairment charges (5)	-	-	8,905	-	-	-	8,905
Investment write-down (5)	-	-	-	1,963	-	-	1,963
Taxes on income	11,044	427	1,793	(1,468)	6	330	11,472
Operating income (loss)	26,468	1,063	(6,003)	(577)	9	(6,429)	27,389
Equity income - utility affiliates (4)	2,669	-	-	-	-	-	2,669
Equity income - non-utility affiliates	-	-	6,079	-	-	6,079	-
Other income (expenses), net	(4,255)	1	(7,767)	315	18	2,022	(13,710)
Interest expense, net	12,324	376	1,009	570	-	401	13,878
Net income (loss)	12,671	506	(8,700)	(2,079)	9	-	2,407
Investments in affiliates, at equity	23,823	-	-	-	-	-	23,823
Total assets	449,820	12,191	58,266	4,531	321	3,455	521,674
Capital expenditures	15,945	407	85	116	-	-	16,553
2000
Revenues from external customers	$310,388	$  23,544	$   1,145	$   3,585	$      7	$   4,743	$333,926
Intersegment revenues	11,942	-	-	-	-	11,942	-
Depreciation and other (2)	21,646	495	63	277	3	343	22,141
Reversal of estimated loss on power contracts (3)	-	1,202	-	-	-	-	1,202
Purchased power disallowance (3)	(2,934)	-	-	-	-	-	(2,934)
Reversal of purchased power disallowance (3)	11,436	-	-	-	-	-	11,436
Taxes on income	7,506	1,528	685	(1,583)	9	(889)	9,034
Operating income (loss)	21,489	3,173	(3,983)	1,125	13	(2,762)	24,579
Equity income - utility affiliates (4)	3,268	-	-	-	-	-	3,268
Equity income - non-utility affiliates	-	-	4,957	(3,734)	-	1,223	-
Other income (expenses), net	5,422	17	531	(26)	25	1,474	4,495
Interest expense, net	13,510	326	814	135	-	347	14,438
Net income (loss)	16,807	2,865	690	(2,332)	13	-	18,043
Investments in affiliates, at equity	24,527	-	-	-	-	-	24,527
Total assets	478,067	12,203	48,688	6,470	313	5,903	539,838
Capital expenditures	14,379	545	44	-	-	-	14,968
1999
Revenues from external customers	$399,268	$  20,551	$   1,316	$  7,306	$      7	$  8,633	$419,815
Intersegment revenues	11,938	-	-	-	-	11,938	-
Depreciation and 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 - utility affiliates (4)	2,844	-	-	-	-	-	2,844
Equity income - non-utility affiliates	-	-	4,471	(5,266)	-	(795)	-
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)	17,254	102	2,061	(2,873)	40	-	16,584
Investments in affiliates, at equity	25,501	-	-	-	-	-	25,501
Total assets	504,120	12,670	46,798	4,526	4,407	8,562	563,959
Capital expenditures	12,723	393	115	-	-	-	13,231

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.
5. See Note 3 herein for CV's investment in non-utility affiliates.
6. See Note 12 herein for CV's retail rates.

Page 78 of 100

Note 16
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 in Operating revenues and income between quarters reflect the seasonal nature of the Company's business (dollars in thousands, except per share amounts):

	Quarter Ended				12-Months
	March	June	September	December	Ended
2001
Operating revenues	$78,032	$73,882	$75,135	$75,427	$302,476
Operating income	$6,126	$7,519	$7,606	$6,138	$27,389
Net income (loss)	$3,897	$326	$3,565	$(5,382)	$2,407
Earnings per share of common stock	$0.30	$(0.01)	$0.27	$(0.50)	$0.06
2000
Operating revenues	$99,949	$73,867	$73,947	$86,163	$333,926
Operating income	$12,564	$2,077	$2,953	$6,985	$24,579
Net income	$7,959	$274	$4,802	$5,008	$18,043
Earnings per share of common stock	$0.66	$(0.01)	$0.38	$0.40	$1.42

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 2002 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 29, 2002.

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 2002 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 29, 2002.

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 2002 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 29, 2002.

Item 13.    Certain Relationships and Related Transactions.

     None.

Page 79 of 100

PART IV

Filed
Herewith
at Page

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, 2001
						Consolidated Statement of Cash Flows, for each of the three years ended December 31, 2001
						Consolidated Balance Sheet at December 31, 2001 and 2000
						Consolidated Statement of Capitalization at December 31, 2001 and 2000
						Consolidated Statement of Changes in Common Stock Equity for each of the three years ended December 31, 2001
						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, 2001
		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.
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)
Page 80 of 100
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)
Page 81 of 100
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)
Page 82 of 100
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)
4-61			Forty-Second Supplemental Indenture, dated as of June 11, 2001 and resolutions connected therewith adopted June 11, 2001. (Exhibit 4-61, Form 8-K, June 28,2001, File No. 1-8222)
Exhibit 10				Material Contracts (*Denotes filed herewith)
		Incorporated herein by reference:
10.1			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)
Page 83 of 100
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)
Page 84 of 100
			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)
			10.8.8					Amendment No. 8 dated November 17, 1999. (Exhibit 10.8.8, Form 10-Q, June 30, 2000, File No. 1-8222)
			10.8.9					Amendment No. 9 dated November 17, 1999. (Exhibit 10.8.9, Form 10-Q, June 30, 2000, File No. 1-8222)
			10.8.10					2001 Amendatory Agreement dated as of September 21, 2001 to which the Company is a party re: Vermont Yankee Nuclear Power Corporation Power Contract. (Exhibit 10.8.10, Form 10-Q, September 30, 2001, 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)
Page 85 of 100
			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)
Page 86 of 100
			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)
Page 87 of 100
			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. 2-48966)
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)
Page 88 of 100
			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)
			10.27.6						1987 Supplementary Power Contract, dated as of April 1, 1987.  (Exhibit 10.27.6, Form 10-Q, June 30, 2000, File No. 1-8222)
			10.27.7						1996 Amendatory Agreement, dated December 1, 1996. (Exhibit 10.27.7, Form 10-Q, June 30, 2000, File No. 1-8222)
			10.27.8						2000 Amendatory Agreement, dated May, 2000. (Exhibit 10.27.8, Form 10-Q, June 30, 2000, 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)
Page 89 of 100
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)
Page 90 of 100
			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)
Page 91 of 100
			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)
Page 92 of 100
			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.
10.84			Settlement Agreement effective dated June 1, 2001 to which the Company is a party re: Vermont Yankee Nuclear Power Corporation. (Exhibit 10-84, Form 10-Q, June 30, 2001, File No. 1-8222)
*  10.85			Form of Secondary Purchaser Settlement Agreement dated December 6, 2001, with Acknowledgement and Consent of VELCO, among the Company, Green Mountain Power Corporation and each of: City of Burlington Electric Department; Village of Lyndonville Electric Department; Village of Northfield Electric Department; Village of Orleans Electric Department; Town of Hardwick Electric Department; Town of Stowe Electric Department; and, Washington Electric Cooperative.
Page 93 of 100
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)
Page 94 of 100
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	10.91				Management Incentive Plan for Executive Officers dated January 1, 2000.  (Exhibit A10.91, Form 10-Q, March 31, 2000, File No. 1-8222)
A	10.92				Officers' Change of Control Agreements as approved April 3, 2000. (Exhibit A10.92, Form 10-Q, March 31, 2000, File No. 1-8222)
A	10.93				Management Incentive Plan for Executive Officers dated January 1, 2001.  (Exhibit A10.93, Form 10-Q, March 31, 2001, File No. 1-8222)
A	10.94				Termination Agreement between the Company and Craig A. Parenzan. (Exhibit A10.94, Form 10-Q, March 31, 2001, 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  Power of Attorney executed by Directors and Officers of Company

27.  Reports on Form 8-K:

     None.

Page 95 of 100

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors of

Central Vermont Public Service Corporation:

We have audited in accordance with auditing standards generally accepted in the United States, 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 4, 2002. Our audit was made for the purpose of forming an opinion on the basic consolidated 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 consolidated financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic consolidated financial statements and, in our opinion, fairly states in all material respects the 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 4, 2002

Page 96 of 100

Schedule II

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES

Reserves

Year ended December 31, 2001

		Additions
	Balance at beginning of year	Charged to cost and expenses	Charged to other accounts	Deductions	Balance at end of year
Reserves deducted from assets    to which they apply:
			$130,682 (1)
			335,712 (2)
Reserve for uncollectible    accounts receivable	$1,655,190	$1,592,704	$466,394	$1,643,497 (3)	$2,070,791
Accumulated depreciation of    miscellaneous properties:
Rental water heater program	$3,845,914	$  254,747	-	$  283,222 (4)	$3,817,439
Other	601,165	95,774	-	-	696,939
	$4,447,079	$  350,521		$  283,222	$4,514,378
Reserves shown separately:
Injuries and damages reserve	$   225,580	-	-	-	$   225,580
Environmental Reserve	$9,532,924		$ 2,305 (5)	$   286,916 (6)	$9,248,313
Company Restructuring	$1,977,687	-	-	$1,977,687 (6)	$                0

(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)  Additional Reserve
(6)  Expenses charged against reserve

Page 97 of 100

Schedule II

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES

Reserves

Year ended December 31, 2000

		Additions
	Balance at beginning of year	Charged to cost and expenses	Charged to other accounts	Deductions	Balance at end of year
Reserves deducted from assets    to which they apply:
			$120,225 (1)
			269,912 (2)
Reserve for uncollectible    accounts receivable	$1,595,433	$1,368,835	$390,137	$1,699,215 (3)	$1,655,190
Accumulated depreciation of    miscellaneous properties:
Rental water heater program	$3,813,045	$  272,747	-	$  239,878 (4)	$3,845,914
Other	530,241	70,924	-	-	601,165
	$4,343,286	$  343,671		$  239,878	$4,447,079
Reserves shown separately:
Injuries and damages reserve	$   225,580	-	-	-	$   225,580
Environmental Reserve	$9,808,314		$ 30,150 (5)	$   305,540 (6)	$9,532,924
Company Restructuring	$3,147,632	-	-	$1,169,945 (6)	$1,977,687
Accumulated provision for rate    refunds	$2,628,479	- -	- -	$2,628,479 (7)	$                0

(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)  Additional Reserve
(6)  Expenses charged against reserve
(7)  Reversal of rate refund reserve

Page 98 of 100

Schedule II

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES

Reserves

Year ended December 31, 1999

		Additions
	Balance at beginning of year	Charged to cost and expenses	Charged to other accounts	Deductions	Balance at end of year
Reserves deducted from assets    to which they apply:
			$112,145 (1)
			310,145 (2)
Reserve for uncollectible    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	$   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

(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 99 of 100

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
                                         (Registrant)

By: /s/ John J. Holtman                                                  
       John J. Holtman, Vice President and Controller

March 12, 2002

     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 12, 2002.

Signature	Title
Robert H. Young* /s/ John J. Holtman                   (John J. Holtman) Frederic H. Bertrand* Robert L. Barnett* William V. Boettcher* Rhonda L. Brooks* Robert G. Clarke* Timothy S. Cobb* Luther F. Hackett* George MacKenzie, Jr.* Mary Alice McKenzie* Janice L. Scites* Herbert H. Tate*	President and Chief Executive Officer, and Director (Principal Executive Officer) Vice President and Controller (Principal Accounting Officer) Chair of the Board of Directors Director Director Director Director Director Director Director Director Director Director

By: /s/ John J. Holtman              
           (John J. Holtman)
            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.

Page 100 of 100

EX-21

EXHIBIT 21.1

Subsidiaries of the Registrant
		State in Which Incorporated
Connecticut Valley Electric Company Inc. (a) (F1) Vermont Electric Power Company, Inc. (b) (F2) C.V. Realty, Inc. (a) (F1) Central Vermont Public Service Corporation -    East Barnet Hydroelectric, Inc. (a) (F1) Catamount Resources Corporation (a) (F1)    Catamount Energy Corporation (a)(c) (F1)    Eversant Corporation. (a)(d) (F1)		New Hampshire Vermont Vermont Vermont Vermont Vermont Vermont
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
(FN) (F1) (F2)	(a)  Included in consolidated financial statements (b)  Separate financial statements do not need to be filed under Regulation S-X, Rule 1-02 (w)        defining a "significant subsidiary", and Rule 3-09, which sets forth the requirement for filing        separate financial statements of subsidiaries not consolidated. (c)  As of December 31, 2001 Catamount Energy Corporation has fourteen wholly-owned subsidiaries.        Of the fourteen subsidiaries, four are operating in foreign countries. (d)  Eversant Corporation has two wholly-owned subsidiaries operating in the United States.

EX-23

EXHIBIT 23.1

CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS

As independent public accountants, we hereby consent to the incorporation of our reports dated February 4, 2002 included in this Form 10-K, into Central Vermont Public Service Corporation's previously filed Form S-3 Registration Statements, File No. 333-57350, and No. 333-09691 and Form S-8 Registration Statements, No. 333-22741, No. 333-22742, No. 333-39664, No. 333-57001, No. 333-57005, No. 333-58102, No. 333-62100, and No. 333-77217.

ARTHUR ANDERSEN LLP

Boston, Massachusetts
March 12, 2002

EX-24

EXHIBIT 24.1

POWER OF ATTORNEY

     KNOW ALL MEN BY THESE PRESENTS, that the undersigned Chief Executive Officer 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, 2001, 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 John J. Holtman 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 pre mises 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 3^rd day of December, 2001.

/s/ Robert H. Young Robert H. Young Chief Executive Officer and Director	/s/ Frederic H. Bertrand Frederic H. Bertrand Chair of the Board of Directors
/s/ John J. Holtman John J. Holtman Vice President and Controller	/s/ Robert L. Barnett Robert L. Barnett, Director
	/s/ William V. Boettcher William V. Boettcher, Director
	/s/ Rhonda L. Brooks Rhonda L. Brooks, Director
	/s/ Robert G. Clarke Robert G. Clarke, Director
	/s/ Timothy S. Cobb Timothy S. Cobb, Director
	/s/ Luther F. Hackett Luther F. Hackett, Director
	/s/ George MacKenzie, Jr. George MacKenzie, Jr., Director
	/s/ Mary Alice McKenzie Mary Alice McKenzie, Director
	/s/ Janice L. Scites Janice L. Scites, Director
	/s/ Herbert H. Tate Herbert H. Tate, Director

EX-10

Exhibit 10.85

Form of
SECONDARY PURCHASER SETTLEMENT AGREEMENT

            This SECONDARY PURCHASER SETTLEMENT AGREEMENT (the "Agreement") is dated as of December 6, 2001 among [                                         named Buyer                                         ] (the "Buyer"), CENTRAL VERMONT PUBLIC SERVICE CORPORATION ("CVPS"), and GREEN MOUNTAIN POWER COMPANY ("GMP", and together with CVPS, the "Sellers").

            WHEREAS, the Sellers are parties to separate power purchase agreements with Vermont Yankee Nuclear Power Corporation ("Vermont Yankee") to purchase their respective entitlement percentages of the power generated from the nuclear generating unit (the "Unit") owned by Vermont Yankee;

            WHEREAS, the Buyer is purchasing a fixed percentage (a "Share") of CVPS's and GMP's combined fifty-five percent (55%) entitlement (the "Vermont Quota") of the capacity and net electric output of the Unit, through November 30, 2002, under a Power Purchase Agreement with Vermont Electric Power Company, Inc. ("VELCO"), dated June 1, 1981 (the "Power Purchase Agreement"), and in accordance with a certain Superseding Three Party Power Agreement, dated February 1, 1990;

            WHEREAS, the Buyer and the Sellers mutually desire to terminate (i) the purchase and sale of the Share, and (ii) the Power Purchase Agreement insofar as it involves the parties to this Agreement;

            NOW THEREFORE, in consideration of the representations, warranties and covenants contained herein and intending to be legally bound hereby, the parties hereby agree as follows:

1. Condition. This Agreement is subject to receipt by Vermont Yankee of the Regulatory Approval (as such term is hereinafter defined).

2. Termination of Power Purchase Agreement. Buyer and the Sellers hereby agree that the Power Purchase Agreement shall terminate at the end of the day on February 28, 2002 (the "Termination Date"), subject only to the acceptance or approval of a notice of termination of the Power Purchase Agreement by the Federal Energy Regulatory Commission (the "FERC"), effective on the Termination Date and without condition unacceptable to the Sellers or the Buyer (the "Regulatory Approval"). On or before December 12, 2001, VELCO shall file notice of termination of the Power Purchase Agreement under Section 35.15 of the regulations of the FERC, in form and substance consistent with this Agreement. The Buyer expressly authorizes VELCO to represent to the FERC that the Buyer consents to the termination of the Power Purchase Agreement and the Buyer shall support such notice of termination. If the FERC declines to accept or approve the termination of the Power Purchase Agreement as set forth in this paragraph, then the Sellers and the Buyer shall negotiate in good faith to effect an equitable adjustment of their rights and obligations under this Agreement with a view to effecting, to the extent possible, the original purpose and intent of this Agreement in light of the FERC action. Any such adjustment shall be reflected in a written amendment to this Agreement.

3. Continuing Obligations. The termination of the Power Purchase Agreement, in accordance with paragraph 2, shall not affect:

1. the obligation of the Buyer to pay all amounts due and owing under the Power Purchase Agreement for service rendered up to and including the Termination Date, in accordance with the terms of the Power Purchase Agreement and as shown on bills properly rendered to Buyer by the Sellers' agent, VELCO, after that date; or
2. the obligation of the Sellers, in accordance with the Settlement Agreement dated June 25, 2001, among the Sellers, Vermont Yankee, the Buyer, and other parties, filed with and accepted by FERC in Docket Nos. EC00-46-000, et al. (the "June 2001 Settlement"), to provide the full amount of the ESP Credit Amount, as that term is defined in Section 4.2 of the June 2001 Settlement, together with accrued interest, to the Buyer upon termination of the Power Purchase Agreement and to reflect in the next monthly statement following the Termination Date, a lump sum credit or refund for any portion of the Buyer's ESP Credit Amount that has not previously been credited to Buyer.

4. Limits of Obligations. Except as specifically set forth in paragraph 3, the Buyer shall not be obligated to make any payments to the Sellers for any portion of any amount charged to VELCO by Vermont Yankee after the Termination Date; the Sellers shall not be obligated to provide any electric power, energy or ancillary service from Vermont Yankee with respect to the Buyer, under the Power Purchase Agreement or otherwise, after the Termination Date (except as may be agreed in a separate power sales agreement); and the Sellers shall not be obligated to provide any payment or credit to the Buyer for any portion of any amount received by the Sellers from Vermont Yankee after the Termination Date.

5. Representations of the Buyer. The Buyer represents and warrants that (a) the Buyer has the power and authority necessary for the execution, delivery and performance of this Agreement, this Agreement has been duly authorized by all necessary corporate action and has been duly executed and delivered on behalf of the Buyer, and this Agreement is the legal, valid and binding obligation of the Buyer, enforceable against the Buyer in accordance with its terms; (b) the execution, delivery and performance of this Agreement will not violate, or result in a breach of or default under, any applicable law or any agreement to which it is a party; and (c) the Buyer has not sold, assigned, granted, or transferred to any individual or entity any of the Released Claims, as defined in paragraph 9.1.

6. Representations of the Seller. Each Seller, severally and not jointly, represents and warrants that (a) such Seller has the power and authority necessary for the execution, delivery and performance of this Agreement, this Agreement has been duly authorized by all necessary corporate action and has been duly executed and delivered on behalf of such Seller, and this Agreement is the legal, valid and binding obligation of such Seller, enforceable against such Seller in accordance with its terms; and (b) the execution, delivery and performance of this Agreement will not violate, or result in a breach of or default under, any applicable law or any agreement to which it is a party.

7. Regulation. This Agreement, and all rights, obligations and performance of the parties hereunder, are subject to all applicable state and federal law and to all duly promulgated orders and other duly authorized action of governmental authorities having jurisdiction over the transactions contemplated hereby.

8. Regulatory Proceedings. Upon execution of this Agreement, the Buyer agrees to promptly proceed to withdraw from all further proceedings in Vermont Public Service Board Docket No. 6545. The Buyer also agrees that it will not (i) intervene, appear, testify or submit any information in any action or proceeding before any governmental authority relating to this Agreement or a certain purchase and sale agreement between Vermont Yankee and Entergy Nuclear Vermont Yankee LLC ("Entergy"), dated as of August 15, 2001, and the transactions contemplated thereby for the purpose of objecting to, preventing or delaying the transactions contemplated thereby or otherwise taking any official position on behalf of the Buyer adverse to the Sellers, Vermont Yankee, other shareholders of Vermont Yankee, or Entergy in connection with such transactions, actions or proceedings; or (ii) cause, solicit or support any other person or entity on behalf of the Buyer to do any of the foregoing; provided, how ever, that this paragraph 8 does not prohibit trustees, directors, officers, members, commissioners or councilors from acting in their individual capacity with a disclaimer that they are not acting as representatives of the Buyer. Subject to the foregoing, the Sellers shall not oppose the Buyer being permitted to appear, in a non-party capacity, to testify or submit information in any such action or proceeding for the purpose of stating that the matters contemplated by this Agreement are in the best interests of its ratepayers. The Buyer further agrees that, as a non-party, it will support this Agreement and the transactions contemplated hereby in proceedings before the Vermont Public Service Board and the FERC to the extent reasonably advisable and necessary to obtain such approvals.

9. Release of Claims.

9.1. Release. Effective on the Termination Date, the Buyer and the Sellers on behalf of themselves, their present, former and future affiliated entities, and any and all present, former and future officers, directors, shareholders, partners, employees, creditors, agents, attorneys, successors, heirs and assigns of the Buyer and the Sellers and/or any present, former or future affiliated entity of the Buyer or the Sellers (collectively, the "Releasors"), do hereby release, remise, and forever discharge each of the Sellers or the Buyer, their present, former and future affiliated entities, and any and all present, former or future officers, directors, shareholders, partners, advisory board members, employees, agents, attorneys, successors, heirs and assigns or any of their present, former and future affiliated entities (collectively, the "Releasees"), of and from all debts, demands, actions, causes of action, suits, accounts, covenants, contracts, agreements, torts, damages, and any and all claims and liabilities whatsoever, of every name and nature, both at law and in equity, including, but not being limited to, any such claims that any of the Releasors now has or ever had or may ever have with or against any of the Releasees relating to or arising out of the Power Purchase Agreement, whether known or unknown, suspected or unsuspected, mature, contingent, direct, derivative, subrogated, or assigned (collectively, the "Released Claims").

9.2. Waiver and Indemnity. The Buyer and the Sellers agree (a) that none of their Releasors will maintain, cause to be maintained, or assist in maintaining (either individually or in concert with another) any further demand, action, claim, lawsuit, arbitration, or similar proceeding, in any capacity whatsoever, against any of the Releasees based upon any of the Released Claims; and (b) to indemnify the Releasees for and against any and all costs, damages, liabilities, or other expenses (including, without limitation, any attorneys' fees) reasonably incurred by any of its Releasees by reason of any violation of clause (a) of this paragraph.

10. General. This Agreement constitutes the entire understanding of the parties with respect to the subject matter hereof and supersedes all prior and current understandings and agreements, whether written or oral, and may not be modified except by a writing signed by each of the parties. If any provision of this Agreement is found invalid or unenforceable, the parties will negotiate appropriate modifications to this Agreement to restore the intended benefits of the original Agreement. The headings in this Agreement are for convenience of reference only and shall not alter, limit or otherwise affect the meaning hereof. This Agreement may be executed in any number of counterparts, which together shall constitute one instrument, and shall bind and inure to the benefit of the parties and their permitted successors and assigns. Each party to this Agreement agrees to perform such other and further acts, and to execute and deliver such other and further documents as may be reasonably necessary to c arry out the provisions of this Agreement. This Agreement shall be governed by and construed in accordance with the laws of the State of Vermont.

Each of the undersigned has caused this Agreement to be executed and delivered by its duly authorized officer as an agreement under seal as of the date first above written.

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
By:
	Name: Title:
GREEN MOUNTAIN POWER COMPANY
By:
	Name: Title:
[named Buyer]
By:
	Name: Title:

ACKNOWLEDGEMENT AND CONSENT

            VERMONT ELECTRIC POWER COMPANY, INC. ("VELCO"), which is technically the seller in respect of the portion of the Vermont Quota sold to the Buyer pursuant to the terms of the Power Purchase Agreement referred to in the Secondary Purchaser Settlement Agreement to which this Acknowledgement and Consent is attached, hereby (a) acknowledges that it is familiar with the Secondary Purchaser Settlement Agreement; and (b) subject to regulatory requirements (i) agrees to be bound by its terms, (ii) consents to the termination of the Power Purchase Agreement in accordance with the terms of the Secondary Purchaser Settlement Agreement, and (iii) agrees to file or cause to be filed a notice of termination with respect to such termination.

VERMONT ELECTRIC POWER COMPANY, INC.
By:
	Name: Title: