Commission file number 1-8222

Central Vermont Public Service Corporation
(Exact name of registrant as specified in its charter)

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.  [    ]

     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.

Form 10-K - 2001

TABLE OF CONTENTS

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Item 1.    Business

     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.

     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.

     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.

     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.

     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.

     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 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.

     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.

     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.

     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.

     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.

     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.

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

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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.

     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:

     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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     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.

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.

     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.

     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.

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.

     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.

     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.

     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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     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.

     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.

     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.

     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.

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     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.

     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.

     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.

     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.

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     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.

     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.

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     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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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:

     (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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     (1) Excluding current portion

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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.

     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."

     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

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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.

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

     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):

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:

     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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     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.

     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.

     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.

     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.

     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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     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.

     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.

     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.

     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.

     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):

      (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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     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.

     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.

     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.

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

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

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.

     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.

     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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     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.

     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.

     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.

     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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     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.

     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.

     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

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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.

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

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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.

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Item 8.    Financial Statements and Supplementary Data.

Index to Financial Statements and Supplementary Data

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     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.

Boston, Massachusetts
February 4, 2002

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

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

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CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in thousands)

CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)

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

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CONSOLIDATED STATEMENT OF CAPITALIZATION
(Dollars in thousands)