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.  [ X ]

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).   Yes        No   X   

     State the aggregate market value of the voting stock held by non-affiliates of the registrant:  $199,949,223 based upon the closing price as of January 31, 2003 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, 2003, there were outstanding 11,761,719 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 6, 2003 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 - 2002

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 147,033 customers in nearly three-quarters of the towns, villages and cities in Vermont. In addition, the Company supplies electricity to one municipal utility, 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 79 percent of total mWh sales for 2002. Sales to the five largest retail customers receiving electric service from the Company during the same period aggregated about 6 percent of the Company's total electric revenues for the year. The Company's resale firm sales accounted for approximately 5 percent and other resale sales which include contract sales, opportunity sales, sales to ISO-New England and short-term system capacity sales accounted for approximately 16 percent of total mWh sales for 2002.

     The Company's wholly owned subsidiary, Connecticut Valley Electric Company Inc. ("Connecticut Valley"), 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 10,629 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 percent of total mWh sales for 2002. Sales to its five largest retail customers during the same period aggregated about 16 percent of Connecticut Valley's total electric revenues for 2002. On December 5, 2002, the Company reached agreement for the sale of Connecticut Valley to Public Service Company of New Hampshire ("PSNH"). See New Hampshire Retail Rates below for additional information related to the sale.

     The Company owns 50.6 percent of the common stock and 46.6 percent of the preferred stock of Vermont Electric Power Company, Inc. ("VELCO"). In the third quarter of 2002, the Company's ownership in VELCO changed from 56.8 percent to 50.6 percent as a result of other owners acquiring additional shares of VELCO's Class C common stock. VELCO owns the high voltage transmission system in Vermont. VELCO's wholly owned subsidiary, Vermont Electric Transmission Company, Inc. ("VETCO"), was formed 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.

     The Company owns 33.23 percent of the common stock of Vermont Yankee Nuclear Power Corporation ("VYNPC"). The Company's ownership percentage changed from 31.3 percent to 33.23 percent in the first quarter of 2002, related to the buy-back of shares held by minority owners of the plant. VYNPC was formed by a group of New England utilities for the purpose of constructing and operating a nuclear-powered generating plant in Vernon, Vermont. On July 31, 2002, VYNPC completed the sale of the Vermont Yankee nuclear power plant to Entergy Nuclear Vermont Yankee, LLC ("Entergy"). VYNPC will continue as a Vermont-based corporation and will administer the purchased power contracts among the former plant owners and Entergy. For additional information see discussion of Equity Ownership in Plants below.

     The Company owns 2 percent of the outstanding common stock of Maine Yankee Atomic Power Company, 2 percent of the outstanding common stock of Connecticut Yankee Atomic Power Company and 3.5 percent of the outstanding common stock of Yankee Atomic Electric Company. For additional information see Nuclear Decommissioning Costs below.

     The Company's wholly owned subsidiary, Catamount Energy Corporation, was formed for the purpose of holding the Company's subsidiaries that invest in unregulated business opportunities. One of its subsidiaries, Catamount Energy Corporation, invests through its wholly owned subsidiaries in non-regulated energy generation projects in North America and Western Europe. Another of its subsidiaries, Eversant Corporation, engages in the

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sale or rental of electric water heaters through a subsidiary, SmartEnergy Water Heating Services, Inc. to customers in Vermont and New Hampshire. See PART II Item 7, and Item 8, Notes 3 and 14, for additional information regarding the Company's diversification activities.

     Other wholly owned subsidiaries of the Company include:

• C.V. Realty, Inc., a real estate company whose purpose is to own, acquire, buy, sell and lease real and personal property and interests therein related to the utility business.
• Central Vermont Public Service Corporation - East Barnet Hydroelectric, Inc. which was created for the purpose of financing and constructing a hydroelectric facility in Vermont, which became operational September 1, 1984 and has been leased and operated by the Company since its in-service date.
• Custom Investment Corporation, which was formed for the purpose of holding passive investments, including the stock of the Company's subsidiaries that invest in regulated business opportunities.

     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 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 nine licenses that will expire in the future at various times under PART I of the Federal Power Act for twelve of its hydroelectric plants. Two additional projects have initial license applications pending. 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.

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     The nuclear generating 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. See discussion of Nuclear Decommissioning Costs below.

     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.

     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 consumers 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.

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     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 in some cases has resulted 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 New Hampshire, where the Company does business, have implemented 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. However, since 2001, the pace of transition slowed due primarily to public and governmental reactions to issues associated with deregulation efforts in California and the collapse of its wholesale electricity market.

     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.

     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. The Company currently plans, absent any unforeseen developments, to refrain from changing rates for its Vermont utility customers until at least 2006.

     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 percent rate increase, or $19 million per annum, effective July 24, 2001. The PSB suspended the rate filing and a schedule was set to review the case.

     On June 26, 2001, the PSB issued an order approving the Company's May 7, 2001 rate case settlement with the DPS. The rate order ended uncertainty over the future recovery of Hydro-Quebec contract costs, allowed a 3.95 percent rate increase, made the January 1, 1999 temporary rates permanent, permitted a return on equity of 11.0 percent, for the 12 months ending June 30, 2002 for the Vermont utility, and created new service quality standards. The Company also agreed to a $9 million one-time write-off ($5.3 million after-tax) of regulatory assets, which was recorded in June 2001, and a rate freeze through January 1, 2003.

     In addition to the provisions outlined above, the rate order requires the Company to return up to $16 million to ratepayers in the event of a merger, acquisition or asset sale if such sale requires PSB approval. The 3.95 percent rate increase became effective with bills rendered July 1, 2001.

     In 2002, the Vermont utility earned approximately $0.4 million, on an after-tax basis, above its allowed rate of return of 11.0 percent. In accordance with its rate case settlement, the Company reduced the Vermont utility's earnings by that amount to satisfy its earnings cap requirement. The Company and DPS are currently in discussions as to the balance sheet classification so as to preserve ratepayer benefit as required by the rate case settlement.

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

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     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 2002 was an over-collection of $215,093 for the FAC and an under-collection of $131,172 for the PPCA. The reconciliation for 2001 was an under-collection of $260,834 for the FAC and an over-collection of $812,472 for the PPCA.

     Connecticut Valley's retail rate tariffs 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 June 1, 2000, the New Hampshire electric utilities began delivery of consistent, statewide energy efficiency programs. The NHPUC had previously approved the design of common, core efficiency programs and on February 27, 2002, Connecticut Valley proposed implementation of specific, non-core energy efficiency programs with recovery of costs for all the energy efficiency programs via an Interim 2002 - 2003 Conservation and Load Management Percentage Adjustment effective June 1, 2002. Connecticut Valley had ceased providing such programs in 1997. On May 31, 2002, the NHPUC approved Connecticut Valley's proposal including a 1.4 percent increase in average retail rates to recover the costs. As required by the NHPUC order, the efficiency programs and related rate increase became effective June 1, 2002.

     On October 1, 2002, Connecticut Valley implemented New Hampshire's statewide low-income energy assistance program referred to as the Tiered Discount Program ("TDP"). Under this NHPUC approved program, New Hampshire electric utilities collect a system benefits charge, apply discounted rates to participant bills, forgive any past due balances at August 31, 2002, deduct any authorized start-up and administrative costs, and remit the balance to the state. A statewide system benefits charge fund makes up the shortfall if the system benefits charge does not wholly reimburse a particular utility. The NHPUC also approved a $0.0012 per kWh surcharge for Connecticut Valley (which is not subject to the system benefits charge) to fund the TDP.

     On December 20, 2002, the NHPUC approved Connecticut Valley's FAC and PPCA rates for 2003 and on December 30, 2002 the NHPUC approved Connecticut Valley's Business Profits Tax Adjustment Percentage for 2003. The 2003 rates are effective January 1, 2003 and result in an overall 8.5 percent rate increase with a revenue increase of $1.6 million.

     See PART II Item 8, Note 12 herein for information regarding New Hampshire Retail Rates.

     Connecticut Valley Sale On December 5, 2002, the Company reached agreement for the sale of Connecticut Valley to Public Service Company of New Hampshire ("PSNH"), New Hampshire's largest electric utility. The sale agreement is the result of months of negotiations among Connecticut Valley, the Company, the Governor's Office of Energy and Community Services, staff of the NHPUC, the Office of Consumer Advocate, the City of Claremont and New Hampshire Legal Assistance. Management believes the sale agreement, as structured, should resolve all issues in litigation over New Hampshire's restructuring plan, Connecticut Valley's rates, recovery of stranded costs and renders moot a pending exit fee decision by the FERC. The proposed closing date for the sale is January 1, 2004.

     Under the terms of the sale agreement, PSNH will pay the Company the book value for Connecticut Valley's franchise utility assets, which approximates $9 million at December 31, 2002. PSNH will acquire Connecticut Valley's poles, wires, substations and other facilities, as well as several independent power obligations, including the Wheelabrator contract. Contemporaneously with the sale, PSNH will pay an additional $21 million to the Company as a stranded cost reimbursement for the power resources the Company acquired to serve Connecticut Valley's customers.

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     The FERC, the NHPUC and possibly the SEC must approve the sale. In addition, as a condition of the sale, the NHPUC must approve the pending settlement in the Wheelabrator docket.

     If the sale transaction does not close, and if there is an adverse resolution of the pending FERC exit fee proceeding, these events would have a material adverse effect on the Company's results of operations, financial condition and cash flows. However, the Company cannot predict the ultimate outcome of this matter.   See PART II Item 8, Note 12 herein for information regarding the Connecticut Valley sale.

     Wholesale Rates  The Company sells firm power to Connecticut Valley under a wholesale rate schedule based on forecast data for each calendar year, which is reconciled to actual data annually. The rate schedule provides for an automatic update of annual capacity rates, as well as a subsequent reconciliation to actual data. The Company filed and the FERC approved 1) a revenue decrease of $1,983,000, or 15.1 percent, for 2002 power costs; 2) a reconciliation of 2001 revenues to actual costs which resulted in a refund of $876,000, including interest; and 3) a revenue decrease of $1,266,000, or 10.6 percent, for 2003 power costs. A significant portion of the 2003 power cost decrease will be partially offset by a significant increase in monthly energy charges, related to a full year effect of 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 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.

     On October 29, 2002, the Company, jointly with the NHPUC, requested that the FERC defer issuance of its final exit fee order to allow for Connecticut Valley to continue working for a negotiated settlement with parties to the New Hampshire restructuring proceeding and the NHPUC. On December 5, 2002, Connecticut Valley, the State of New Hampshire, the City of Claremont and PSNH reached agreement for the sale of Connecticut Valley to PSNH. Under the terms of the agreement, which is described in more detail above, PSNH will pay an additional $21 million to the Company as a stranded cost reimbursement for the power resources the Company acquired to serve Connecticut Valley's customers, thus rendering moot the exit fee decision by the FERC.

     Absent the sale, if the Company was unable to obtain approval by the FERC of an exit fee from its power supply arrangement and Connecticut Valley was forced to terminate its relationship as a wholesale customer of the Company (the earliest termination date that could presently occur pursuant to the wholesale rate schedule is December 31, 2004) it is possible that the Company would be required to recognize a pre-tax loss under the power supply arrangement totaling approximately $27.4 million as of December 31, 2004. The Company would also be required to write-off approximately $0.6 million pre-tax of regulatory assets associated with its wholesale business as of December 31, 2004. The sale of Connecticut Valley to PSNH as currently structured, which includes the receipt of $21 million in stranded cost recovery, is expected to resolve these issues. However, Management cannot predict whether the sale will occur under these terms.

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     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. For the 12 months ended December 31, 2002, under long-term contracts with these qualifying facilities, Connecticut Valley purchased 39,258 mWh, of which 93 percent 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 Ap peals, which denied the appeal, but indicated that Connecticut Valley could seek relief from the NHPUC. On May 12, 2000, Connecticut Valley filed a petition with the NHPUC seeking 1) to amend the contract to permit purchase of net, rather than gross, output of the facility and 2) a refund, with interest, of past purchases of the difference between net and gross output.

     On March 29, 2002, the NHPUC issued an order denying Connecticut Valley's petition. The NHPUC further found that its original 1983 order did not authorize sales in excess of 3.6 MW and ordered that Connecticut Valley discontinue purchases in excess of that amount at preferential rates. Wheelabrator has been making sales at the long-term rates for up to 4.5 MW of capacity and related energy since it began operations in 1987.

     On April 29, 2002, Connecticut Valley, Wheelabrator, NHPUC Staff and the Office of Consumer Advocate submitted a Stipulation of Settlement with the NHPUC that requires Wheelabrator to make five annual payments of $150,000 and a sixth payment of $25,000, and Connecticut Valley to make six annual payments of $10,000, all of which will be credited to customer bills. The Stipulation of Settlement will not become effective unless and until it is approved by the NHPUC. The settlement does not otherwise change the terms of the existing contract between Connecticut Valley and Wheelabrator.

     As a condition to the sale of Connecticut Valley to PSNH, the NHPUC must approve the Stipulation of Settlement. Additionally, under the terms of the sale agreement, PSNH will acquire several of Connecticut Valley's independent power obligations, including the Wheelabrator contract. See PART II Item 8, Note 12 herein for information regarding the Wheelabrator contract.

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     The Company's and Connecticut Valley's energy generation and purchased power required to serve their retail and firm wholesale customers was 2,541,533 mWh for the year ended December 31, 2002. The maximum one-hour integrated demand during that period was 423.9 mW, which occurred on December 3, 2002. The Company's and Connecticut Valley's total energy generation and purchased power in 2002, including that related to all resale customers, was 3,005,349 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, 2002. For additional information related to purchased power costs, refer to PART II Item 7, herein.

1. Approximately 60 percent of the mWh generated and purchased from Vermont Yankee were prior to the July 31, 2002 sale of the plant, in which the Company had an equity ownership in the plant. The remaining purchases occurred after the sale under a purchased power agreement as described in more detail below.

     The Company owns and operates 20 hydroelectric generating facilities in Vermont, which have an aggregate nameplate capability of 44.7 MW and two oil-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:

     The Company receives its share of 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.

Hydro-Quebec  The Company is purchasing varying amounts of power from Hydro-Quebec under the Vermont Joint Owners ("VJO") Power Contract through 2016. The VJO includes a group of Vermont electric companies and municipal utilities, of which the Company is a participant. Related contracts were negotiated between the Company and Hydro-Quebec, which in effect altered the terms and conditions contained in the original contract by reducing the overall power requirements and related costs.

     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, 2002, the Company's obligation is approximately 46 percent of the total VJO Power Contract through 2016, which translates to approximately $800 million, on a nominal basis, to the Company. The average annual amount of capacity that the Company will purchase from January 1, 2003 through October 31, 2012 is approximately 143 MW, with lesser amounts purchased through October 31, 2016. See PART II Item 8, Note 13 for additional information regarding the Hydro-Quebec contract.

Vermont Yankee On July 31, 2002, VYNPC completed the sale of the Vermont Yankee nuclear power plant to Entergy Nuclear Vermont Yankee, LLC ("Entergy"). The sale transaction included a purchased power contract ("PPA") with prices that generally range from 3.9 cents to 4.5 cents per kilowatt-hour through 2012, subject to a "low-market adjuster" effective November 2005, that protects the current Vermont Yankee owner-utilities, including the Company and its power consumers, in the event power market prices drop significantly. If the market prices rise, however, contract prices are not adjusted upward. The PPA is forecasted to result in higher purchased power costs in the initial years of the contract with decreased costs in future years when compared to continued ownership of the plant.

     The Company receives its 35 percent entitlement of Vermont Yankee output sold by Entergy to VYNPC. Under the PPA between Entergy and VYNPC, VYNPC pays Entergy only for generation at fixed rates; VYNPC in turn includes the PPA charges from Entergy with certain residual costs of service through a FERC tariff to the Company

and the other VYNPC sponsors. Accordingly, as a result of the sale, the Company no longer bears the operating costs and risks associated with running the plant or the costs and risks associated with the eventual decommissioning of the plant.

Cogeneration/Independent Power Qualifying Facilities The Company purchases power from a number of IPPs who own qualifying facilities under the Public Utility Regulatory Policies Act of 1978. These qualifying facilities produce energy using hydroelectric, biomass and refuse-burning generation. The majority of these purchases are made from a state-appointed purchasing agent who purchases and redistributes the power to all Vermont utilities.

In 2002, the Company and Connecticut Valley received 198,371 mWh under these long-term contracts, representing approximately 7.6 percent and 15 percent of the total mWh purchases and total purchased power expense for the period, respectively. 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

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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 England 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.

     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.

     In March 2003, ISO-New England implemented Standard Market Design ("SMD"). ISO-New England also provides the main marketplace for participants to secure open access transmission for transactions delivered on the Pool Transmission Facilities. See PART II, Item 7 herein for additional information regarding SMD and Regional Transmission Organizations.

     NEPOOL's peak for the year occurred on August 14, 2002 and totaled 25,348 MW. The Company's peak demand occurred on December 3, 2002 and totaled 423.9 MW; the Company had a reserve margin of approximately 32.9 percent, at the time of this peak.

     The Company has sufficient 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. See Part II Item 7, herein.

     The Company is responsible for paying its joint-ownership percentage of Millstone Unit #3 decommissioning costs and its entitlement percentages of decommissioning costs related to Maine Yankee, Connecticut Yankee and Yankee Atomic (the "Yankee companies").

     The Company has a 1.7303 percent joint-ownership interest in the Millstone Unit #3 facility, in which Dominion Nuclear Corporation ("DNC") is the lead owner with approximately 93.47 percent of the plant joint-ownership. The Company is responsible for its joint-ownership share of decommissioning costs. The Company's contributions to the Millstone Unit #3 Trust Fund have ceased based on DNC's representation to various regulatory bodies that the Trust Fund, for its share of the plant, exceeded the Nuclear Regulatory Commission's ("NRC") minimum calculation required. The Company could choose to renew funding at its own discretion as long as the minimum requirement is met or exceeded.

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     The Yankee companies have been permanently shut down and are currently conducting decommissioning activities. Each plant revises its revenue requirement forecasts on an ongoing basis, including estimates for decommissioning costs, based on site-specific studies, through the projected completion date of all decommissioning activity. Based on revised estimates in 2002, the costs of decommissioning Maine Yankee, Connecticut Yankee and Yankee Atomic increased by $40 million, $150 million and $190 million, respectively, over prior estimates utilized at the FERC. These increased costs are attributable mainly to increases in the projected costs of spent fuel storage, security and liability and property insurance.

     The Company's share of estimated future payments related to the decommissioning efforts based on current forecasts, including the incremental cost increases described above, are as follows (dollars in millions):

     The decision to prematurely retire these nuclear power plants was based on economic analyses of the costs of operating them compared to the costs of closing them and incurring replacement power costs over the remaining period of the plants' operating licenses. The Company believes that the premature retirements 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's, Connecticut Yankee's and Yankee Atomic's decommissioning costs will be recovered through the regulatory process. 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.

Maine Yankee In 1997, the Maine Yankee nuclear power plant was prematurely retired from commercial operation. The Company relied on Maine Yankee for less than 5 percent of its required system capacity. Currently, costs billed to the Company by Maine Yankee, including a provision for ultimate decommissioning of the plant are expected to be paid over the period 2003 through 2008, and are being collected from the Company's customers through existing retail and wholesale rate tariffs.

     Maine Yankee's current billings to the sponsor companies are based on its most recent rate case settlement, approved by the FERC on June 1, 1999. The settlement provides for recovery of anticipated future payments for closing, decommissioning and recovery of the remaining investment in Maine Yankee and also resolved all issues raised in the FERC proceeding, including those raised by the secondary purchasers, who purchased Maine Yankee power through agreements with the original owners. Under the rate case settlement, Maine Yankee agreed to file with the FERC a rate proceeding with an effective date for new rates of no later than January 1, 2004. Maine Yankee is expected to seek recovery of the incremental cost increase described above in its next FERC rate filing.

Connecticut Yankee In 1996, the Connecticut Yankee nuclear power plant was prematurely retired from commercial operation. The Company relied on Connecticut Yankee for less than 3 percent of its required system capacity. Currently, costs billed to the Company by Connecticut Yankee, including a provision for ultimate decommissioning of the plant, are expected to be paid over the period 2003 through 2007 and are being collected from the Company's customers through existing retail and wholesale rate tariffs.

     Connecticut Yankee's current billings to the sponsor companies are based on its most recent FERC approved rates, which became effective September 1, 2000. Connecticut Yankee is expected to seek recovery of the incremental cost increase described above in its next scheduled FERC rate filing.

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Yankee Atomic In 1992, the Yankee Atomic nuclear power plant was retired from commercial operation. The Company relied on Yankee Atomic for less than 1.5 percent of its system capacity. Costs related to Yankee Atomic are not included in the Company's existing rates due to Yankee Atomic's determination in July 2001 that it had collected sufficient funds to complete the decommissioning effort and discontinued related billings to the sponsor companies at that time. Changes to decommissioning cost estimates, however, are subject to ongoing review and such changes would require FERC review and approval.

     Yankee Atomic plans to file its rate application with the FERC for recovery of the incremental cost increase described above in March 2003. Billings to sponsors for recovery of these costs are expected to resume in June 2003, for recovery through 2010.

     See Part II Item 7, and Item 8 Note 2, herein.

The Price-Anderson Act ("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 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 million per incident per nuclear unit in any one year. The maximum assessment is adjusted at least every five years to reflect inflation. The Act has been renewed since it was first enacted in 1957. The Act expired in August 2002; negotiations on a 15-year reauthorization of the Act are ongoing and require approval by the full House and Senate before taking effe ct. Existing commercial nuclear power plants are "grandfathered" under the most recent reauthorization of the law. Currently the Company could become liable for an aggregate of approximately $0.9 million of such maximum assessment per incident per year.

     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 50.6 percent of VELCO's outstanding common stock, the Four-Party Agreement does not provide the Company the ability to exercise control over 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 56.8 percent of VELCO's outstanding Class B voting common stock, 27.8 percent of VELCO's outstanding Class C non-voting common stock (approved by the FERC on July 15, 2002), and 46.6 percent of VELCO's outstanding Class C preferred stock. 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, 20,000 shares of Class C common stock, $100 par value, and 125,000 shares of Class C preferred stock, $100 par value, of which 60,000, 16,163 and 97,068 shares, respectively, were outstanding at December 31, 2002. In addition, three issues of First Mortgage Bonds, aggregating $51,760,000 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, 2002. 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. 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, 2002) 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, 2002 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 interconnection transmission facilities in northeastern Vermont, which were completed at a total cost of approximately $140 million. Under a support agreement relating to the Company's participation in the facilities, the Company is obligated to pay its 4.55 percent share of Phase I Hydro-Quebec capital costs over a 20-year recovery period through and including 2006. The Company also participated in the construction of Phase II Hydro-Quebec transmission facilities constructed throughout New England, which were completed at a total cost of approximately $487 million. 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 fir m

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power contract. Under a similar support agreement, the New England participants, including the Company, have contracted to pay their proportionate share of the total cost of constructing, owning and operating the Phase II facilities, including capital costs. The Company is obligated to pay its 5.132 percent share of Phase II Hydro-Quebec capital costs over a 25-year recovery period through and including 2015.

     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 Vermont Energy Efficiency Utility ("EEU"), created by the State of Vermont, began operation in January 2000. 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 the EEU's 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 ("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. An initial set of rules for the DUP was filed by the parties in Docket No. 6290 as a Memorandum of Understanding ("MOU"), which was approved by the PSB on January 15, 2003. The MOU provides: 1) an energy efficiency screening tool that is under development; 2) an agreement on default planning assumptions that are subject to modification semi-annually as well as changes to fit specific area conditions; 3) continues the collaboration of the parties to update the rules as necessary and to share information; and 4) establishes ongoing collaborative for a number of area specific collaboratives ("ASC") to examine resource investm ent options for potentially constrained transmission or distribution areas; the Company has five such ASCs.

     Catamount Resources Corporation was formed for the purpose of holding the Company's subsidiaries that invest in unregulated business opportunities. One of its subsidiaries, Catamount Energy Corporation, invests through its wholly owned subsidiaries in non-regulated energy generation projects in North America and Western Europe. Another of its subsidiaries, Eversant Corporation, engages in the sale or rental of electric water heaters through a subsidiary, SmartEnergy Water Heating Services, Inc. to customers in Vermont and New Hampshire.

     Local Union No. 300, affiliated with the International Brotherhood of Electrical Workers represents operating and maintenance employees of the Company and Connecticut Valley Electric Company. At December 31, 2002 the Company and its wholly owned subsidiaries including Catamount, employed 565 persons, of which 225 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 percent effective December 30, 2001, December 29, 2002 and January 4, 2004, enhanced pension benefits and employee contributions for health-care coverage will increase from 7 to 20 percent of the cost over the three year period of the new contract.

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     In general, the Region tends to experience its peaks in summer months while the Company's maximum loads tend to occur in the months of December and January. Winter recreational activities, longer hours of darkness and heating loads from cold weather usually cause the Company's maximum loads of electric mWh sales to occur in January or late December and air conditioning contributes towards peaks in the summer.

     CAPITAL EXPENDITURES

     The Company's capital expenditures totaled approximately $14.4 million, $16.6 million and $15.0 million in 2002, 2001 and 2000, respectively. The Company's five-year capital expenditures for the Vermont utility business are expected to range from approximately $85 million to $90 million for the years 2003 through 2007. This estimate is subject to continuing review and adjustment and actual capital expenditures may vary from this estimate. For additional information regarding capital expenditures and working capital see Part II, Item 7 herein.

     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 Executive 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.; Custom Investment Corporation; Catamount Resources

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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.; 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.

     Mrs. Gibson joined the Company in 2002. Prior to joining the Company, from 2000 to 2002, she served as Corporate Vice President and Controller at Exelon Corporation; from 1998 to 2000 she served as Corporate Vice President and Controller at PECO Energy Company. Mrs. Gibson serves as Director, Senior Vice President, Chief Financial Officer, and Treasurer for the following CVPS subsidiaries: CVPSC - East Barnet Hydroelectric, Inc.; CV Realty, Inc.; Custom Investment Corporation; Catamount Resources Corporation; Eversant Corporation; and, SmartEnergy Water Heating Services, Inc. She also serves as Senior Vice President, Chief Financial Officer, and Treasurer for the following CVPS subsidiaries: Connecticut Valley Electric Company Inc. and AgEnergy, Inc.

     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: CVPSC - East Barnet Hydroelectric, Inc.; C.V. Realty, Inc.; Connecticut Valley Electric Company Inc.; Custom Investment Corporation; 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.; Custom Investment Corporation; 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. He resigned as a CVPS officer on March 8, 2002. Prior to resigning from CVPS, he served as Senior Vice President from February 2001 to March 2002; 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 presently serves as Director, Vice Chair, and Chief Executive Officer of Catamount Energy Corporation, and as Director of SmartEnergy Water Heating Services, Inc., CVPS subsidiaries.

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     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 percent interest in an oil generating plant in Maine; a 20 percent interest in a wood, gas and oil-fired generating plant in Vermont; a 1.73 percent interest in a nuclear generating plant in Connecticut; and a 47.35 percent 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 7,689 miles of overhead distribution lines and about 321 miles of underground distribution lines, all of which are located in Vermont except for about 22 miles in New Hampshire and about two 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 two miles of transmission lines, about 442 miles of overhead distribution lines and about 14 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.

     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 adverse effect on the financial position or the results of operations of the Company, except as otherwise disclosed herein.

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

     There were no matters submitted to security holders during the fourth quarter of 2002.

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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:

     (c)  Common Stock dividends have been declared quarterly. Cash dividends of $.22 per share were paid for all
           quarters of 2001 and 2002.

     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 percent 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 percent 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 percent to 25 percent of Total Capitalization, such dividends on Common Stock during the year ending on the date of such dividend declaration shall be limited to 75 percent of the Net Income Available for Dividends on Common Stock for that year. The defined terms identified abo ve 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, 2002, the Common Stock Equity of the unconsolidated Company was 55 percent 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 actions of regulators and legislators, pending sale of the Company's wholly owned subsidiary Connecticut Valley Electric Company ("Connecticut Valley"), performance of the Vermont Yankee nuclear power plant, weather conditions, and performance of the Company's non-regulated businesses. The Company cannot predict the outcome of any of these matters.

CRITICAL ACCOUNTING POLICIES
Preparation of the Company's financial statements in accordance with accounting principles generally accepted in the United States of America ("GAAP") requires Management to make estimates and assumptions that affect 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 significant accounting policies used in 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 ("PSB"), the New Hampshire Public Utilities Commission ("NHPUC") and the Federal Energy Regulatory Commission ("FERC"), with respect to rates charged for service, accounting and other matters pertaining to regulated operations. As such, the Company currently prepares its financial statements in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71, Accounting for the Effects of Certain Types of Regulation ("SFAS No. 71"), for its regulated Vermont service territory, FERC-regulated wholesale businesses and Connecticut Valley's New Hampshire service territory. In order for a company to report under SFAS No. 71, a company's rates must be designed to recover its costs of providing service and the company must be able to collect those rates from customers. If rate recovery becomes unlikely or uncertain, whether due to competition or regulatory action, this accounting standard would no lon ger apply to the Company's regulated operations. In the event the Company determines that it no longer meets the criteria for applying SFAS No. 71, the accounting impact would be an extraordinary non-cash charge to operations of approximately $45.7 million on a pre-tax basis as of December 31, 2002, assuming that no stranded cost recovery would be allowed through a rate mechanism. Criteria that could give rise to the discontinuance of SFAS No. 71 include 1) increasing competition that restricts the Company's ability to establish prices to recover specific costs and 2) a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. Management periodically reviews these criteria to ensure the continuing application of SFAS No. 71 is appropriate. Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, Management believes future recovery of its regulatory assets in the State of Vermont and the State of New Hampshire for the Company's retail and wholesale businesses is 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 value of the long-lived asset. See Note 3 to the Consolidated Financial Statements for further discussion of impairment of non-utility investments.

Utility Plant and Maintenance Utility plant is recorded at cost. The cost of additions, including betterments and replacements of units of property, is charged to utility plant. Based on regulatory accounting, maintenance and repairs, including the cost of removing minor items of property, are expensed as incurred. The cost of units of property replaced or retired, plus removal or disposal costs, less salvage, is charged to accumulated depreciation. The Company capitalizes direct costs and certain indirect costs, including the cost of debt and equity capital associated with construction and retirement activity, as prescribed by GAAP and in accordance with regulatory practices.

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Depreciation The Company has a significant investment in electric plant.  Depreciable assets related to generation, transmission, distribution and general functions represent approximately 95 percent of total depreciation. The Company depreciates these assets utilizing a composite rate, which currently includes a component for net negative salvage. The Company uses a straight-line basis over the useful life of the related assets, which corresponds with the anticipated physical lives of these assets in most cases. In order to substantiate the remaining physical lives of the investment in electric plant, outside consultants are engaged to perform depreciation studies on that property. The most recent depreciation study was completed and implemented in the second quarter of 2002. As prescribed by GAAP and regulatory practices, adjustments to the estimated depreciable lives of electric plant are recorded on a prospective basis.

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 the related property, plant or equipment, they are considered executory in nature.

Revenues  Revenues related to the sale of electricity are generally recorded when service is rendered or when electricity is distributed to customers. Electricity sales to individual customers are based on the monthly reading of their meters. Estimated unbilled revenues are recorded at the end of each monthly accounting period. The Company follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the monthly accounting period. The determination of unbilled revenues requires the Company to make various estimates including 1) energy generated, purchased and resold, 2) losses of energy over transmission and distribution lines, 3) kilowatt-hour usage by retail customer mix - residential, commercial and industrial, and 4) average retail customer pricing rates. Unbilled revenues as of December 31, 2002, 2001 and 2000 were $16 million, $16.4 million and $17.1 million, respectively.

Pension and Postretirement Benefits The Company records pension and other postretirement benefit costs in accordance with SFAS No. 87, Employers' Accounting for Pensions, and SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions. Under these accounting standards, assumptions are made regarding the valuation of benefit obligations and performance of plan assets. Delayed recognition of differences between actual results and those assumed is a required principle of these standards. This approach allows for systematic recognition of changes in benefit obligations and plan performance over the working lives of the employees who benefit under the plans. The following is a list of the primary assumptions, which are reviewed annually for the September 30 measurement date.

• Discount Rate - The discount rate is used to record the value of benefits, which are based on future projections, in terms of today's dollars.  As of September 30, 2002, the discount rate was decreased from 7.25 percent to 6.5 percent.

• Expected Return on Plan Assets ("ROA") - The Company projects the future ROA based principally on prior performance and receives guidance from the Company's actuaries. The projected future value of assets reduces the benefit obligation a company will record. As of September 30, 2002, the ROA was reduced from 8.5 percent to 8.25 percent.

• Rate of Compensation Increase - The Company projects employees' annual pay increases, which are used to project employees' pension benefits at retirement. As of September 30, 2002, the rate of compensation increase was changed from 4.5 percent to 4 percent.

• Health Care Cost Trend - The Company projects expected increases in the cost of health care. For measurement purposes, a 10 percent and 9.5 percent annual rate of increase in the per capita cost of covered health care benefits was assumed for fiscal 2003, for pre-65 and post-65 claims costs, respectively.

• Amortization of Gains/(Losses) - The Company can select the method by which gains or losses are recognized in financial results. These gains or losses are created when actual results differ from estimated results based on the above assumptions. The Company recognizes these gains and losses ratably over a five-year period.

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     A variance in the discount rate, expected return on plan assets, rate of compensation increase or amortization method could have a significant impact on the pension costs recorded under SFAS No. 87. A variance in health care cost trend assumptions could have a significant impact on costs recorded under SFAS No. 106 for postretirement medical expense. The impact of a one-percentage-point increase or decrease in the assumed health care cost trend as calculated by the Company's actuaries is $1.2 million and ($1.1 million), respectively, as of December 31, 2002. The market value of pension plan assets has been affected by sharp declines in the capital markets. As a result, the Company anticipates increases in pension expense for 2003 of $1.7 million; pension cost and cash funding requirements are expected to increase in future years and could become even more material without a substantial recovery in the capital markets. See Note 10 to the Consolidated Financial Statements.

Income Taxes In accordance with SFAS No. 109, Accounting for Income Taxes ("SFAS No. 109"), the Company recognizes tax assets and liabilities for the cumulative effect of all temporary differences between financial statement carrying amounts and the tax basis of assets and liabilities. Investment tax credits associated with utility plant are deferred and amortized ratably to income over the lives of the related properties.  A valuation allowance is recorded to reduce the carrying amounts of deferred tax assets unless it is more likely than not that such assets will be realized. See Note 11 to the Consolidated Financial Statements.

Earnings Overview The Company's 2002 net income was $19.8 million, or $1.56 per basic and $1.53 per diluted share of common stock, which equates to a 9.6 percent consolidated return on average common equity. This compares to 2001 net income of $2.4 million, or $.06 per basic and diluted share of common stock, and 2000 net income of $18 million, or $1.42 per basic and $1.41 per diluted share of common stock. The consolidated return on average common equity was 0.4 percent for 2001 and 8.6 percent for 2000.

2002 vs. 2001: Excluding all nonrecurring items, the Company's net income for 2002 compared to 2001 is as follows:

     Offsetting the favorable impacts to 2002 earnings were, 1) higher net power costs of $3.4 million after-tax, or $.29 per share, primarily related to a 2001 reversal of a December 2000 accrual for estimated costs for installed capacity deficiency charges in ISO-New England with no similar reversal in 2002 and lower ISO-New England market prices for resale sales; and 2) higher operating and other costs of $2.4 million after-tax, or $.21 per share of common stock, primarily related to a $0.6 million, or $.05 per share, one-time payment related to closing the

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Vermont Yankee sale, higher net transmission costs of $0.4 million, or $.04 per share, higher property tax expense of $0.4 million, or $.04 per share, an increase in bad debt reserves of $0.7 million, or $.06 per share, due to several announced bankruptcies, lower interest and dividend income of $0.7 million, or $.06 per share, a 2001 settlement of $0.3 million, or $.03 per share, related to Wyman generating station with no similar item in 2002, higher other operating expenses of $0.2 million, or $.02 per share, offset by a $1.0 million, or $.09 per share, reversal of certain environmental reserves.

     The Company's June 26, 2001 rate case settlement allows for an 11.0 percent rate of return on common equity for the Vermont utility. In 2002, the Company's Vermont utility earned approximately $0.4 million, on an after-tax basis, above its allowed rate of return. In accordance with its rate case settlement, the Company reduced the Vermont utility's earnings by that amount to satisfy its earnings cap requirement. The related deferral of approximately $0.7 million pre-tax is included in Other deferred credits on the Company's Consolidated Balance Sheet. The Company and Vermont Department of Public Service ("DPS") are currently in discussions as to the balance sheet classification so as to preserve ratepayer benefit as required by the rate case settlement.

2001 vs. 2000: Excluding all nonrecurring items, the Company's net income for 2001 compared to 2000 is as follows:

     Excluding the above nonrecurring items, factors that contributed to the $3.4 million increase in earnings include: 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 percent 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; 5) lower net losses at Eversant of $1.3 million, or $.12 per share, related to Eversant's investment in HSS, offse t by higher business development costs and a fourth quarter 2001 accrual for a potential income tax liability; and 6) lower earnings at Catamount of $0.2 million, or $.01 per share.

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Operating Revenues and Megawatt-hour ("mWh") Sales Revenues from operations and related mWh sales for 2002, 2001 and 2000 are summarized below:

      (1) Firm sales are compensatory and are based on FERC filed tariffs.
      (2) Entitlement sales are transfers of the Company's entitlement in a plant or generating facility in which it has a firm
            entitlement in, such as Vermont Yankee and Hydro-Quebec. In 2001 and 2000 the Company transferred or sold specific
            MW entitlements of its share of Vermont Yankee including plant output and related capacity costs.
      (3) Alliance sales are related to an alliance with Virginia Power that supplied wholesale power primarily in the Northeast states.
            In the third quarter of 1999, the Company and Virginia Power agreed to discontinue the Alliance and related transactions
            ended in 2000.

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

2002 vs. 2001: Operating revenues increased $0.9 million as a result of the following factors:

• Retail sales increase of $7.1 million resulting from higher average retail rates due to a 3.95 percent retail rate increase beginning July 1, 2001, and a 0.9 percent increase in mWh sales.
• Entitlement sales decrease of $7.3 million due to the completion of a five-year power contract that ended in October 2001.
• Other resale sales decrease of $0.3 million primarily due to lower ISO-New England market prices, offset by an 8.7 percent increase in mWh sales for the same period. The increased mWh sales are attributed to the end of the Vermont Yankee entitlement sale described below and an 11.8 percent increase in the Company's share of Vermont Yankee output beginning March 2, 2002, as a result of the early return of Vermont Yankee entitlements from the secondary purchasers. The additional output that the Company receives from the Vermont Yankee plant is either used to support own-load needs or sold in the short-term market mostly to ISO-New England. Although the Vermont Yankee plant was sold in July 2002, the Company receives approximately 35 percent of the plant output through a purchased power agreement. See Power Supply Matters for more information regarding the Vermont Yankee sale.
• Other revenues increase of $1.5 million primarily due to the sale of non-firm transmission under the Company's open access transmission tariff.

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2001 vs. 2000: Operating revenues decreased approximately $31.5 million as a result of the following factors:

• Retail sales increased $2.4 million due to the favorable impact of a 3.95 percent increase in retail rates beginning July 1, 2001, which contributed approximately $4.9 million, and the favorable impact of customer mix and unit pricing, which contributed $1.7 million. Offsetting these favorable impacts was a 1.9 percent decrease in mWh sales resulting in a $4.2 million reduction in retail sales revenue.
• Entitlement sales decreased $3.5 million due in part to a five-year power contract in which the Company sold approximately 15 percent of its share of Vermont Yankee output at full cost; the contract ended in October 2001. Additionally, in 2000 and 2001, the Company entered into short-term transactions in which it sold energy from Vermont Yankee based on a portion of its MW entitlement, and in return purchased energy from other nuclear plants based on the same MW. Offsetting purchases are included in the Purchased Power and Produced Energy (mWh) table below. In 2001, the sale part of the transactions of approximately $1.1 million was included in Other sales, while in 2000 the sale part of the transactions of approximately $2.2 million was included in Entitlement sales.
• Alliance sales decreased $22.2 million due to termination of an alliance with Virginia Power.
• Other resale sales decreased $4.4 million due to lower output and purchases from the Company's power resources, which affected 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 this decrease were Vermont Yankee unit swap transactions, which were included in Other in 2001 and Entitlement in 2000.
• Other revenues decreased $3.8 million compared to 2000 primarily due to 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.

Net Purchased Power and Production Fuel Costs The Company discusses in more detail its power supply sources, purchased power commitments and liabilities regarding nuclear investments in Power Supply Matters below.

     The cost components of net purchased power and production fuel for 2002, 2001 and 2000 are summarized in the following table (dollars in thousands):

2002 vs. 2001: The sale of Vermont Yankee effective July 31, 2002, resulted in a significant change to the Company's purchased power cost structure when comparing 2002 with 2001. While the Company continues to purchase a similar share of plant output, all payments are made on an energy (mWh) basis under a purchased power agreement ("PPA") that became effective after the sale. Because of high PPA prices in 2002, costs were significantly higher compared to continued ownership of the plant. In anticipation of these increased costs the Company sought and the Vermont Public Service Board ("PSB") approved an Accounting Order that authorized the

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Company to defer incremental cost increases in 2002 resulting from the sale. In 2002 Vermont Yankee purchases had a favorable impact on energy and capacity costs of approximately $1.8 million compared to an unfavorable impact of approximately $3.4 million if not for the Accounting Order. The following is a summary of factors that impacted Vermont Yankee costs in 2002 compared to 2001.

• The Company is no longer responsible for the plant's capacity costs and all purchases under the PPA are recorded as energy purchases. Prior to the sale, the great majority of Vermont Yankee costs were recorded as capacity costs.
• In March 2002, as a result of negotiations with secondary purchasers, the Company's entitlement share of output from the plant increased by 11.8 percent. These additional purchases resulted in a $2.2 million and $3.2 million increase in capacity and energy costs, respectively, while supplying an additional 118,000 mWh to the Company.
• The Company deferred approximately $5.2 million in energy costs based on the approved Accounting Order resulting in a mitigation of $5.2 million in energy costs.
• The favorable impact of a $1.3 million reduction of purchased power expense due to state tax benefits available to Vermont Yankee, resulting in a $1.3 million decrease in capacity costs.

     Overall, the $6.5 million increase in net purchased power and production fuel costs resulted from the following factors:

• Lower market prices for energy throughout much of 2002 reduced revenue used to offset the cost of power, resulting in $3.2 million of additional net costs.
• Power requirements related to increased retail sales, losses, and capacity needs added $1.1 million.
• Lower net Vermont Yankee costs of approximately $1.8 million as explained above.
• A $5.4 million unfavorable impact resulting from items in 2001 with no comparable items in 2002, which are explained in more detail below.

2001 vs. 2000: Capacity costs decreased $10.7 million due to favorable items in 2001 including the June 26, 2001 rate order, which ended the Hydro-Quebec power cost disallowances, resulting in a $2.9 million reversal of a second-quarter 2001 accrual for under-recovery of power costs, and a $2.5 million reversal of a December 2000 accrual for estimated costs for installed capacity in ISO-New England due to the resolution of a December 2000 FERC Order. Additionally, Vermont Yankee capacity costs were lower by $3.8 million, net of deferrals for refueling outage costs, due to lower decommissioning costs beginning July 1, 2001, and lower interest costs and operational efficiencies at the plant.

• Energy costs decreased $27.6 million primarily due to Alliance-related purchases in 2000 of approximately $22 million, which were offset by Alliance resale sales. Other factors included decreased 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.
• 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.
• Entitlement and other resale sales decreased approximately $30 million primarily related to the Alliance-related sales and other factors as explained in Operating Revenues above.

Other Operating Costs Other major elements of the Consolidated Statement of Income are discussed below.

Maintenance expenses There was no significant variance in maintenance expenses in 2002 compared to 2001. The $3.4 million increase in 2001 compared to 2000 is primarily due to higher service restoration costs related to storm activity in the first quarter of 2001.

Equity in earnings of affiliates The $1.2 million increase in equity in earnings of affiliates in 2002 compared to 2001 is primarily due to state tax benefits available to Vermont Yankee as a result of the sale. See Vermont Yankee below for more detail.

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Other income, net Variances related to utility and non-utility operations are shown in the following table (dollars in millions) and explained in more detail below.

     Utility The one-time payment of $1 million is related to closing the Vermont Yankee sale. The $9 million write-off in 2001 is related to the Company's June 26, 2001 Vermont rate order, which is discussed in more detail in Rates and Regulation below. The unfavorable $5.4 million variance for 2001 compared to 2000 was due to the favorable Millstone Unit #3 settlement in 2000.

     Non-utility Catamount net revenues and expenses increased $3.9 million for 2002 versus 2001, related to higher Catamount equity earnings in 2002 from several of Catamount's investments and realized development revenue upon the sale of one of its investments in the fourth quarter of 2002, offset by project development and third-party related costs in 2002. The Catamount asset impairment charges in 2002, 2001 and 2000 are related to asset impairment charges of $2.8 million, $8.9 million and $1 million, respectively. The $2 million Eversant write-down in 2001 is related to its investment in HSS.  See Diversification below for more detail.

Interest on long-term debt There was no significant variance in interest on long-term debt in 2002 compared to 2001 or in 2001 compared to 2000. Interest expense reflects the retirement of first mortgage bonds of $7 million in 2002, $4 million in 2001, and $16.5 million in 2000. Interest on long-term debt includes non-utility interest expense of $1.2 million, $1 million and $0.8 million for 2002, 2001 and 2000, respectively.

Other interest expense Other interest expense decreased $1 million in 2002 compared to 2001 and increased $0.6 million in 2001 compared to 2000, primarily due to the 2002 settlement of an IRS audit resulting in the reversal of a related interest expense accrual previously recorded in the fourth quarter of 2001. Other interest expense includes non-utility interest of $0.5 million and $0.1 million for 2001 and 2000, respectively.

Income taxes See Note 11 to the Consolidated Financial Statements for detail regarding fluctuations in the level of expense.

Extraordinary loss, net of tax benefit  An extraordinary loss of $0.2 million in the third quarter of 2001 resulted from the application of SFAS No. 71 at Connecticut Valley.

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Sources of Energy The Company purchases approximately 90 percent of its power under several contracts of varying duration. The Company's purchased power portfolio includes a mix of base load and schedulable resources and additional wholly owned resources to help cover the Company's peak load periods. A breakdown of the Company's energy sources is shown below:

     The Company's joint-ownership interests include 1.7303 percent in Unit #3 of the Millstone Nuclear Power Station, 20 percent in Joseph C. McNeil, a 53 MW wood-, gas- and oil-fired unit, and 1.78 percent joint-ownership in Wyman #4, a 619 MW oil-fired unit. Wholly owned units include 20 hydroelectric generating units, two oil-fired and one diesel-peaking unit with a combined nameplate capability of 73.6 MW.

     The Company has long-term power contracts with Hydro-Quebec and with Vermont Yankee Nuclear Power Corporation ("VYNPC") for a combined total of approximately 85 percent of the Company's total energy (mWh) purchases. Additionally, the Company is required to purchase power from various Independent Power Producers under long-term contracts. See Power Contract Commitments below for more detail regarding these contracts.

     The Company also engages in short-term purchases and sales with ISO-New England, and with other electric utilities primarily in New England, in order to minimize the net costs and risk of serving its customers.

     Based on present commitments and contracts, the Company expects that net purchased power and production fuel costs will average approximately $133 million to $141 million per year for the years 2003 through 2007, however, these costs are in large part dependent upon wholesale power market prices. The Company's long-term power forecasts indicate a long position, or excess energy to meet load requirements, of approximately 400,000 mWh annually. On a daily basis, the mWh excess is typically sold to ISO-New England with related sales revenue used to offset purchased power expenses. In order to narrow the variance of its forecasted power position, the Company entered into forward sale transactions averaging 312,000 mWh in 2003.

Hydro-Quebec The Company is purchasing varying amounts of power from Hydro-Quebec under the Vermont Joint Owners ("VJO") Power Contract through 2016 and related contracts negotiated between the Company and Hydro-Quebec, which in effect altered the terms and conditions contained in the original contract by reducing the overall power requirements and related costs. 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 remaining VJO participants, including the Company, will "step-up" to the defaulting party's share on a pro rata basis. As of December 31, 2002, the Company's obligation is approximately 46 percent of the total VJO Power Contract through 2016, which translates to approximately $800 million, on a nominal basis, over the contract term. The average annual amount of capacity that the Company will purchase from January 1, 2003 through October 31, 2012 is 143 MW, with lesser amounts purchased through October 31, 2016.

     In 2002, the Company purchased approximately $59 million of energy and related capacity under the existing contracts with Hydro-Quebec. The Company's estimated purchases under these contracts at a 75 percent load factor are expected to be approximately $57.7 million, $61.2 million, $61.9 million, $62.5 million and $62.9 million for the years 2003 through 2007, respectively. See Note 13 to the Consolidated Financial Statements for further discussion of this contract.

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Vermont Yankee On July 31, 2002, VYNPC completed the sale of the Vermont Yankee nuclear power plant to Entergy Nuclear Vermont Yankee, LLC ("Entergy"). The sale transaction included a purchased power contract ("PPA") with prices that generally range from 3.9 cents to 4.5 cents per kilowatt-hour through 2012, subject to a "low-market adjuster" effective November 2005, that protects the current Vermont Yankee owner-utilities, including the Company and its power consumers, in the event power market prices drop significantly. If the market prices rise, however, contract prices are not adjusted upward. The PPA is forecasted to result in higher purchased power costs in the initial years of the contract with decreased costs in future years when compared to continued ownership of the plant.

     The Company receives its 35 percent entitlement of Vermont Yankee output sold by Entergy to VYNPC. Under the PPA between Entergy and VYNPC, VYNPC pays Entergy only for generation at fixed rates; VYNPC in turn includes the PPA charges from Entergy with certain residual costs of service through a FERC tariff to the Company and the other VYNPC sponsors. Accordingly, as a result of the sale, the Company no longer bears the operating costs and risks associated with running the plant or the costs and risks associated with the eventual decommissioning of the plant.

     In 2002 the Company purchased approximately $60.2 million of energy and capacity from Vermont Yankee, based on its entitlement share in the plant before and after the sale. The Company's estimated purchases related to Vermont Yankee are expected to be approximately $65.9 million, $61.5 million, $56.7 million, $60.7 million and $56 million for the years 2003 through 2007, respectively.

Independent Power Producers ("IPPs") The Company purchases power from a number of IPPs who own qualifying facilities under the Public Utility Regulatory Policies Act of 1978. These qualifying facilities produce energy using hydroelectric, biomass and refuse-burning generation. The majority of these purchases are made from a state-appointed purchasing agent who purchases and redistributes the power to all Vermont utilities.

     In 2002, the Company received 198,371 mWh under these long-term contracts, representing approximately 7.6 percent and 15 percent of the Company's total mWh purchases and total purchased power expense for the period, respectively. The total mWh received under these contracts includes 145,572 mWh allocated by the Purchasing Agent, VEPP Inc., and 36,675 mWh purchased by Connecticut Valley from a waste-to-energy electric generating facility owned by Wheelabrator Claremont Company, L.P. The Company's estimated purchases from IPPs are expected to be approximately $22.5 million, $22.8 million, $22.3 million, $22.8 million and $21.1 million for the years 2003 through 2007, respectively.

     See Note 12 and Note 13 to the Consolidated Financial Statements for additional information regarding Wheelabrator and contract negotiations with IPPs, respectively.

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

     The Company is currently in the process of relicensing or preparing to relicense six separate hydroelectric projects under the Federal Power Act. These projects, some of which are grouped together under a single license, represent approximately 24.5 MW, or about 54.8 percent 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 6.35-MW hydroelectric station on the Lamoille River. The Vermont Natural Resources Council ("VNRC") and others proposed removal of the 1948 facility, which produces power to energize approximately 3,000 homes per year. In April 2002, the parties including the Town of Milton and the DPS entered into a Conceptual Agreement outlining a negotiated settlement of the issues relating to project relicensing, including the removal of Peterson Dam.

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     In January 2003, the Company, the State of Vermont, VNRC and other parties reached an agreement to allow the Company to relicense the four dams owned and operated by the Company on the Lamoille River. According to the agreement, the Company will receive a water quality certificate from the State, which is needed for the FERC to relicense the facilities for 30 years. The agreement also stipulates that the Company must begin decommissioning Peterson Dam in approximately 20 years. The agreement, however, requires PSB approval of full rate recovery related to decommissioning the Peterson Dam including full rate recovery of replacement power costs when the dam is out of service. The Company cannot predict the outcome of this matter.

Nuclear Decommissioning The Company is responsible for paying its joint-ownership percentage of Millstone Unit #3 decommissioning costs and its entitlement percentages of decommissioning costs related to Maine Yankee, Connecticut Yankee and Yankee Atomic (the "Yankee companies").

Millstone Unit #3 The Company has a 1.7303 percent joint-ownership interest in the Millstone Unit #3 facility, in which Dominion Nuclear Corporation ("DNC") is the lead owner with approximately 93.47 percent of the plant joint-ownership. The Company is responsible for its joint-ownership share of decommissioning costs. The Company's contributions to the Millstone Unit #3 Trust Fund have ceased based on DNC's representation to various regulatory bodies that the Trust Fund, for its share of the plant, exceeded the Nuclear Regulatory Commission's ("NRC") minimum calculation required. The Company could choose to renew funding at its own discretion as long as the minimum requirement is met or exceeded.

     In accordance with ratemaking treatment, the incremental costs attributable to replacement energy and maintenance costs, incurred during regular nuclear refueling outages, are deferred and amortized ratably to expense until the next regularly scheduled refueling outage, which is typically over 18 months. Millstone Unit #3 had a scheduled refueling outage in early 2001 and another in September 2002. The Company deferred approximately $1 million for energy and maintenance costs related to the September 2002 refueling outage.

Yankee Companies The Yankee companies have been permanently shut down and are currently conducting decommissioning activities. Each plant revises its revenue requirement forecasts on an ongoing basis, including estimates for decommissioning costs, based on site-specific studies, through the projected completion date of all decommissioning activity. Based on revised estimates in 2002, the costs of decommissioning Maine Yankee, Connecticut Yankee and Yankee Atomic increased by $40 million, $150 million and $190 million, respectively, over prior estimates utilized at the FERC. These increased costs are attributable mainly to increases in the projected costs of spent fuel storage, security and liability and property insurance.

     The Company's share of estimated future payments related to the decommissioning efforts based on current forecasts, including the incremental cost increases described above, are as follows (dollars in millions):

     The Company's share of estimated revenue requirements are reflected on the Consolidated Balance Sheets as either regulatory assets or other deferred charges, depending on current recovery in existing rates, and nuclear decommissioning liabilities (current and non-current). At December 31, 2002, the Company had regulatory assets of approximately $9 million and $3.8 million related to Maine Yankee and Connecticut Yankee, respectively, and other deferred charges of $3.5 million and $7.9 million related to Connecticut Yankee and Yankee Atomic, respectively. These amounts are subject to ongoing review and revisions and the Company adjusts the associated regulatory assets, other deferred charges and nuclear decommissioning liabilities accordingly.

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     The decision to prematurely retire these nuclear power plants was based on economic analyses of the costs of operating them compared to the costs of closing them and incurring replacement power costs over the remaining period of the plants' operating licenses. The Company believes that the premature retirements 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's, Connecticut Yankee's and Yankee Atomic's decommissioning costs will be recovered through the regulatory process. 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.

Maine Yankee In 1997, the Maine Yankee nuclear power plant was prematurely retired from commercial operation. The Company relied on Maine Yankee for less than 5 percent of its required system capacity. Currently, costs billed to the Company by Maine Yankee, including a provision for ultimate decommissioning of the plant are expected to be paid over the period 2003 through 2008, and are being collected from the Company's customers through existing retail and wholesale rate tariffs.

     Maine Yankee's current billings to the sponsor companies are based on its most recent rate case settlement, approved by the FERC on June 1, 1999. The settlement provides for recovery of anticipated future payments for closing, decommissioning and recovery of the remaining investment in Maine Yankee and also resolved all issues raised in the FERC proceeding, including those raised by the secondary purchasers, who purchased Maine Yankee power through agreements with the original owners. Under the rate case settlement, Maine Yankee agreed to file with the FERC a rate proceeding with an effective date for new rates of no later than January 1, 2004. Maine Yankee is expected to seek recovery of the incremental cost increase described above in its next FERC rate filing.

Connecticut Yankee In 1996, the Connecticut Yankee nuclear power plant was prematurely retired from commercial operation. The Company relied on Connecticut Yankee for less than 3 percent of its required system capacity. Currently, costs billed to the Company by Connecticut Yankee, including a provision for ultimate decommissioning of the plant, are expected to be paid over the period 2003 through 2007 and are being collected from the Company's customers through existing retail and wholesale rate tariffs.

     Connecticut Yankee's current billings to the sponsor companies are based on its most recent FERC approved rates, which became effective September 1, 2000. Connecticut Yankee is expected to seek recovery of the incremental cost increase described above in its next scheduled FERC rate filing.

Yankee Atomic In 1992, the Yankee Atomic nuclear power plant was retired from commercial operation. The Company relied on Yankee Atomic for less than 1.5 percent of its system capacity. Costs related to Yankee Atomic are not included in the Company's existing rates due to Yankee Atomic's determination in July 2001 that it had collected sufficient funds to complete the decommissioning effort and discontinued related billings to the sponsor companies at that time. Changes to decommissioning cost estimates, however, are subject to ongoing review and such changes would require FERC review and approval.

     Yankee Atomic plans to file its rate application with the FERC for recovery of the incremental cost increase described above in March 2003. Billings to sponsors for recovery of these costs are expected to resume in June 2003, for recovery through 2010.

     The Company ended 2002 with cash and cash equivalents of $60.4 million, an increase of $14.9 million from December 31, 2001. The increase resulted from $42.6 million provided by operating activities, $0.1 million provided by the effect of exchange rate changes on cash, offset by $2 million used for investing and $25.8 million used for financing. 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 resulting from $30.2 million provided by operating activities, offset by $30.6 million used for investing activities and $2.1 million used for financing activities.

     The Company's liquidity is primarily affected by the level of cash generated from operations, reduced by the funding requirements of its ongoing construction programs.  The Company believes that it will generate sufficient cash flow from operations to fund its anticipated needs through at least 2004. The $75 million Second Mortgage Bonds mature on August 1, 2004. It is currently anticipated that all or a majority of the debt will be refinanced at maturity. The type, timing and terms of future financing that the Company may need will depend upon its cash needs, the availability of refinancing sources and the prevailing conditions in the financial markets.

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Operating Activities  Net income, depreciation, deferred income taxes and investment tax credits, including after-tax non-cash items of $2.8 million related to Catamount's asset impairment charges and $12.1 million related to deferrals of the Vermont Yankee fuel rod maintenance and sale-related costs, provided cash of $30.6 million. Working capital and other operating activities provided approximately $12 million of cash.

Investing Activities Construction and plant expenditures used cash of approximately $14.4 million, Conservation and Load Management programs used $0.2 million, investment in VELCO used $0.4 million and other investing activities used $0.3 million, while $13 million was provided by non-utility investments, mostly related to the sale of Catamount's investments in Gauley River and Heartlands and $0.3 million was provided by the return of capital from utility investments.

     The Company's five-year capital expenditures for the Vermont utility business are expected to range from approximately $85 million to $90 million for the years 2003 through 2007.

Financing Activities Dividends paid on common stock were $10.3 million, while preferred stock dividends were $1.9 million. The pay down of capital lease obligations required $1.1 million, while the retirement of long-term debt and preferred stock used $14.2 million. The Company's dividend reinvestment program provided $1.3 million and sale of common stock from the Company's Treasury shares provided $0.4 million.

Effect of Exchange Rate Changes on Cash  Net cash flow provided by the effect of exchange rate changes on cash was $0.1 million.  The increase was the result of Catamount's foreign currency translations.

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.

Obligations  The following table is a summary of the Company's obligations as of December 31, 2002.

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     Based on outstanding debt at December 31, 2002, the aggregate amount of utility long-term debt maturities and sinking fund requirements are $10.5 million and $75 million for the years 2003 and 2004.  No payments are due for 2005 through 2007. It is currently anticipated that all, or a majority of, the $75 million Second Mortgage Bonds, maturing at August 1, 2004, will be refinanced at maturity. Substantially all of the Company's 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 with Citizen's Bank of Massachusetts, expiring on August 31, 2003. These letters of credit support three series of Industrial Development/Pollution Control Bonds, totaling $16.3 million. The letter of credit supporting the $5.5 million Seabrook bonds was effective on August 22, 2002. The Company had in place a supplemental indenture allowing the letter of credit to transfer. 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, 2002, the Company was in compliance with all debt covenants related to its various debt agreements.

Catamount Catamount has a $25 million revolving credit/term loan facility and letters of credit, of which $21.3 million was outstanding at December 31, 2002. The facility expired on November 12, 2002 and on December 31, 2002 Catamount and its lender entered into the First Amendment to the facility that, among other things, extended the revolver facility for an additional two years. Under the two-year extension, Catamount can borrow against new operating projects subject to the terms and conditions of the facility. Additionally, the outstanding revolver loans were converted to amortizing loans on a two-year term-out schedule. 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, 2002, including Catamount's office building mortgage, the aggregate amount of Catamount's long-term debt maturities are $10.4 million and $11.1 million for the years 2003 and 2004, respectively. Catamount's long-te rm debt contains financial and non-financial covenants. Catamount received a waiver by the lender on October 31, 2002 for capital expenditures that exceeded the annual budget. At December 31, 2002, Catamount was in compliance with all covenants under the revolver. In early January 2003, Catamount applied $12.6 million, representing the after-tax proceeds from its investment sales, against its outstanding loan balance resulting in a $8.7 million loan balance.

Eversant In 2002, SmartEnergy Water Heating Services, Inc., a wholly owned subsidiary of Eversant, retired a $1.1 million term loan with Bank of New Hampshire.

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

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Credit Ratings Current credit ratings of the Company's securities by Standard & Poor's and Fitch IBCA ("Fitch") were reaffirmed during 2002. The rating affirmations reflect improvement in the Company, subsequent to the sale of the Company's interest in the Vermont Yankee nuclear plant, due to reduced business risk and the Company's ability to recover all purchased power costs in rates.  Credit ratings should not be considered a recommendation to purchase stock. Current credit ratings are as follows:

Catamount Resources Corporation was formed for the purpose of holding the Company's subsidiaries that invest in non-regulated business opportunities including Catamount and Eversant.

Catamount Catamount invests through its wholly owned subsidiaries in non-regulated energy generation projects in the United States and Western Europe. As of December 31, 2002, through its wholly owned subsidiaries, Catamount has interests in eight operating independent power projects located in Glenns Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont; Thetford, England; Hopewell, Virginia; Thuringen, Germany and Mecklenburg-Vorpommern, Germany.

     In 2001, Catamount undertook a comprehensive strategic review of its operations and refocused its efforts from being an investor in late-stage renewable energy to being primarily focused on developing, owning and operating wind energy projects. Wind energy is competitive with other forms of electric generation and has low production costs compared to other renewable energy sources. Environmental and energy security concerns support growth in the wind sector.  Catamount is currently pursuing the sale of certain of its interests in non-wind electric generating assets. Proceeds from sales will be used to pay down the outstanding loan balance to the extent required per the revolving credit/term loan facility and then be reinvested in the development of new wind projects or 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 June 2001, Catamount established Catamount Development GmbH, a German corporate entity, 100 percent owned by Catamount Heartlands Corp., a wholly owned subsidiary of Catamount. The company was formed to hold Catamount's interests in German "greenfield" development projects or projects that would be purchased by Catamount in early- to mid-stage development.

     In 2002, Catamount established Catamount Energy Ltd., a UK and Wales limited company, which is ultimately 100 percent owned by two of Catamount's wholly owned subsidiaries. The company was formed to hold Catamount's interests in UK "greenfield" development projects or projects that would be purchased by Catamount in early to mid-stage development.

     Catamount's earnings were $1.5 million for 2002 and its loss and earnings were $8.7 million and $0.7 million for 2001 and 2000, respectively. See Competition - Risk Factors below and Note 3 to the Consolidated Financial Statements for more information regarding Catamount.

Eversant Eversant has a $1.4 million equity investment, representing a 12.1 percent ownership interest in The Home Service Store, Inc. ("HSS"), as of December 31, 2002. HSS has established a network of affiliate contractors who perform home maintenance repair and improvements for HSS members. HSS began operations in 1999 and is subject to risks and challenges similar to a company in the early stage of development. In September 2001, Eversant recorded a $1.2 million after-tax write-down of its investment in HSS to fair value.  Eversant had previously recorded losses of $9 million related to its investment in HSS.   Eversant accounts for its investment in HSS on a cost basis.

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     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 marketed and sold 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.  On November 6, 2002, Westfalia filed a Petition to Confirm the Arbitrator's Award in the United States District Court for the Western District of Wisconsin, which effectively sought to expand the Arbitrator's Award. The Company submitted an answer seeking to dismiss the Petition to the extent it sought costs in excess of those established by the Arbitrator. The Company cannot predict the outcome of the proceeding.

     SmartEnergy Water Heating Services, Inc. ("SEWHS"), had earnings of $0.3 million, $0.4 million and $0.5 million for 2002, 2001 and 2000, respectively.

     In the first quarter of 2002, the Company decided to discontinue Eversant's efforts to pursue non-regulated business opportunities but will continue its water heating business through SEWHS. Overall, Eversant incurred net losses of $0.5 million, $2.1 million and $2.3 million for 2002, 2001 and 2000, respectively.  See Note 3 to the Consolidated Financial Statements for more information regarding Eversant.

     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. The Company currently plans, absent any unforeseen developments, to refrain from changing rates for its Vermont utility customers until at least 2006.

2000 Retail Rate Case In an effort to mitigate eroding earnings and cash flow prospects, on November 9, 2000, the Company filed with the PSB a request for a 7.6 percent rate increase, or $19 million per annum, effective July 24, 2001. The PSB suspended the rate filing and a schedule was set to review the case.

     On June 26, 2001, the PSB issued an order approving the Company's May 7, 2001 rate case settlement with the DPS. The rate order ended uncertainty over the future recovery of Hydro-Quebec contract costs, allowed a 3.95 percent rate increase, made the January 1, 1999 temporary rates permanent, permitted a return on equity of 11 percent, for the 12 months ending June 30, 2002 for the Vermont utility, and created new service quality standards. The Company also agreed to a $9 million one-time write-off ($5.3 million after-tax) of regulatory assets, which was recorded in June 2001, and a rate freeze through January 1, 2003.

     In addition to the provisions outlined above, the rate order requires the Company to return up to $16 million to ratepayers in the event of a merger, acquisition or asset sale if such sale requires PSB approval. The 3.95 percent rate increase became effective with bills rendered July 1, 2001.

     As part of the Company's June 26, 2001 rate order, the Company agreed that all amounts collected from the Hydro-Quebec Ice Storm settlement would be applied first to reduce the remaining balance of deferred costs related to the arbitration, with the remaining balance, if any, applied to reduce other regulatory asset accounts as specified by the DPS and approved by the PSB. In July 2001 Hydro-Quebec and the VJO agreed to a final settlement, 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 deferred ice storm arbitration costs. 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 to other regulatory assets. On September 10, 2002 and in response to a PSB request, the Company filed its amended proposal as agreed to with the DPS.

     On October 4, 2002, the PSB issued an Order approving the Company's proposal for reducing certain regulatory assets by approximately $2 million through application of the remaining Hydro-Quebec settlement and the ongoing Millstone Unit #3 decommissioning non-payments. Although the Company is recovering the Millstone Unit #3 decommissioning costs in rates, its payments for decommissioning have ceased. In the third quarter of 2002, based

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on the PSB Order, the Company reduced certain of its regulatory assets related to Conservation and Load Management by approximately $2 million. The Company will account for the ongoing Millstone Unit #3 decommissioning non-payments as a regulatory liability, with carrying charges, to be addressed in the Company's next rate proceeding.

     In 2002, the Vermont utility earned approximately $0.4 million, on an after-tax basis, above its allowed rate of return of 11.0 percent. In accordance with its rate case settlement, the Company reduced the Vermont utility's earnings by that amount to satisfy its earnings cap requirement. The related deferral of approximately $0.7 million pre-tax is included in Other deferred credits on the Company's Consolidated Balance Sheet. The Company and DPS are currently in discussions as to the balance sheet classification so as to preserve ratepayer benefit as required by the rate case settlement.

     See Note 12 to the Consolidated Financial Statements for more detail related to Vermont retail rates.

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

     See Note 12 to the Consolidated Financial Statements for more detail related to New Hampshire retail rates.

Connecticut Valley Sale On December 5, 2002, the Company reached agreement for the sale of Connecticut Valley to Public Service Company of New Hampshire ("PSNH"), New Hampshire's largest electric utility. The sale agreement is the result of months of negotiations among Connecticut Valley, the Company, the Governor's Office of Energy and Community Services, staff of the NHPUC, the Office of Consumer Advocate, the City of Claremont and New Hampshire Legal Assistance. Management believes the sale agreement, as structured, should resolve all issues in litigation over New Hampshire's restructuring plan, Connecticut Valley's rates, recovery of stranded costs and renders moot a pending exit fee decision by the FERC. The proposed closing date for the sale is January 1, 2004.

     Under the terms of the sale agreement, PSNH will pay the Company the book value for Connecticut Valley's franchise utility assets, which approximates $9 million at December 31, 2002. PSNH will acquire Connecticut Valley's poles, wires, substations and other facilities, as well as several independent power obligations, including the Wheelabrator contract. Contemporaneously with the sale, PSNH will pay an additional $21 million to the Company as a stranded cost reimbursement for the power resources the Company acquired to serve Connecticut Valley's customers.

     The FERC, the NHPUC and possibly the SEC must approve the sale. In addition, as a condition of the sale, the NHPUC must approve the pending settlement in the Wheelabrator docket.

     The sale will result in either a gain or loss; however, the nature and size of such gain or loss will be highly dependent upon power market price forecasts at the time of the sale and mitigation efforts both before and after the sale. Accordingly, the Company cannot estimate at this time such a gain or loss.

     If the sale transaction does not close, and if there is an adverse resolution of the pending FERC exit fee proceeding, these events would have a material adverse effect on the Company's results of operations, financial condition and cash flows. However, the Company cannot predict the ultimate outcome of this matter.

FERC Exit Fee 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

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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 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.

     On October 29, 2002, the Company, jointly with the NHPUC, requested that the FERC defer issuance of its final exit fee order to allow for Connecticut Valley to continue working for a negotiated settlement with parties to the New Hampshire restructuring proceeding and the NHPUC. On December 5, 2002, Connecticut Valley, the State of New Hampshire, the City of Claremont and PSNH reached agreement for the sale of Connecticut Valley to PSNH. Under the terms of the agreement, which is described in more detail above, PSNH will pay an additional $21 million to the Company as a stranded cost reimbursement for the power resources the Company acquired to serve Connecticut Valley's customers, thus rendering moot the exit fee decision by the FERC.

     Absent the sale, if the Company was unable to obtain approval by the FERC of an exit fee from its power supply arrangement and Connecticut Valley was forced to terminate its relationship as a wholesale customer of the Company (the earliest termination date that could presently occur pursuant to the wholesale rate schedule is December 31, 2004) it is possible that the Company would be required to recognize a pre-tax loss under the power supply arrangement totaling approximately $27.4 million as of December 31, 2004. The Company would also be required to write-off approximately $0.6 million pre-tax of regulatory assets associated with its wholesale business as of December 31, 2004. The sale of Connecticut Valley to PSNH as currently structured, which includes the receipt of $21 million in stranded cost recovery, is expected to resolve these issues. However, Management cannot predict whether the sale will occur under these terms.

Wheelabrator Power Contract Connecticut Valley purchases power from several Independent Power Producers, who own qualifying facilities as defined by the Public Utility Regulatory Policies Act of 1978. For the twelve months ended December 31, 2002, under long-term contracts with these qualifying facilities, Connecticut Valley purchased 39,258 mWh, of which 93 percent 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 appea l, but indicated that Connecticut Valley could seek relief from the NHPUC. On May 12, 2000, Connecticut Valley filed a petition with the NHPUC seeking 1) to amend the contract to permit purchase of net, rather than gross, output of the facility and 2) a refund, with interest, of past purchases of the difference between net and gross output.

     On March 29, 2002, the NHPUC issued an order denying Connecticut Valley's petition. The NHPUC further found that its original 1983 order did not authorize sales in excess of 3.6 MW and ordered that Connecticut Valley discontinue purchases in excess of that amount at preferential rates. Wheelabrator has been making sales at the long-term rates for up to 4.5 MW of capacity and related energy since it began operations in 1987.

     On April 29, 2002, Connecticut Valley, Wheelabrator, NHPUC Staff and the Office of Consumer Advocate submitted a Stipulation of Settlement with the NHPUC that requires Wheelabrator to make five annual payments of $150,000 and a sixth payment of $25,000, and Connecticut Valley to make six annual payments of $10,000, all of which will be credited to customer bills. The Stipulation of Settlement will not become effective unless and until it is approved by the NHPUC. The settlement does not otherwise change the terms of the existing contract between Connecticut Valley and Wheelabrator.

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     A hearing on the Stipulation of Settlement was held on June 7, 2002 with a focus on determining whether the Stipulation is in the public interest. The NHPUC issued an Order on July 5, 2002, in which it did not rule on the Stipulation of Settlement and instead announced that it would appoint an independent mediator to work with all parties to see if a mutually agreeable settlement of the case could be achieved. The NHPUC selected an independent mediator and, after several mediation sessions, the mediator issued a report on December 18, 2002, which stated that the parties opposing the Stipulation of Settlement before the mediation continued to oppose it after the mediation.

     As a condition to the sale of Connecticut Valley to PSNH, the NHPUC must approve the Stipulation of Settlement. Additionally, under the terms of the sale agreement, PSNH will acquire several of Connecticut Valley's independent power obligations, including the Wheelabrator contract.

     The electric utility industry is in a period of transition that in some cases has resulted 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 New Hampshire, where the Company does business, have implemented 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. During 2001, however, the pace of transition slowed due primarily to public and governmental reactions to issues associated with deregulation efforts in California and the collapse of its wholesale electricity market.

Vermont There have been three primary sources of Vermont governmental activity attempting to restructure the electric industry in Vermont: 1) the Governor's Working Group, created by the former Governor of Vermont, which completed its work in 1998; 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 and the proceeding has been closed. 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.

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

     In 1999, the FERC issued a Notice of Proposed Rulemaking ("NOPR") that would amend FERC's regulations under the Federal Power Act to facilitate the formation of regional transmission organizations ("RTO"). In late 1999 the FERC issued Order No. 2000, regarding the formation of RTOs. The Company has participated in various filings and proceedings related to formation of RTOs since Order No. 2000 was first issued. More recently, on November 22, 2002, NEPOOL notified the FERC that it was withdrawing the proposal made with New York to form the Northeast RTO and, subsequently, announced that it would propose an RTO for New England. It is anticipated that this filing will be made mid-year 2003. Transmission-owning entities in New England, including Vermont Electric Power Company, Inc. ("VELCO") and the Company, are participating in discussions intended to result in a transmission network company to provide the transmission services needed under the FERC's RTO Order.

     Order No. 2000 is generally designed to separate the governance and operation of the transmission system from generation companies and other market participants. At this time, the Company is unable to predict the outcome of this matter or its impact on the Company.

Standard Market Design On July 31, 2002, FERC issued a NOPR for Standard Market Design ("SMD"). FERC intends to establish nationally consistent power market rules and offers additional options for RTO formation. On September 20, 2002, the FERC accepted in part ISO-New England's request to implement an SMD governing wholesale energy sales in New England. The SMD will include a system of locational marginal pricing of energy under which prices for load will be determined by zone and based in part on transmission congestion and marginal losses experienced in each zone. Previous to SMD the costs of network congestion and losses were spread across the region's load-serving entities on a pro rata basis. Based on data observed during indicative trials beginning in the fall of 2002, congestion appears to be most significant in the load centers of eastern Massachusetts and southwestern Connecticut, while losses may be high in Vermont. Initially, the State of Vermont is expected to comprise a single < /P>

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load zone under the plan. Generators will receive location-specific prices for the nodes at which they interconnect with the New England electric network. The vast majority of the Company's generating resources are either located in the Vermont Zone or delivered at locations that are not expected to congest significantly in or en route to the Vermont Zone under expected circumstances. Because of their magnitude, congestion and loss costs are the two categories of power related costs that have the greatest potential to increase or decrease the net cost of serving load relative to the pre-SMD environment. An auction-based system of Financial Transmission Rights ("FTR") will be implemented to allow participants to hedge congestion risks. An associated auction revenue allocation scheme will be implemented to distribute the proceeds of the FTR auction to load entities that experience congestion and entities that invest to increase the capacity of the regional network.

     SMD will also include the creation of a location-specific day-ahead market that will allow participants the opportunity to settle transactions involving load and generation one day in advance of the real time spot market. In general, the Company either owns or holds entitlements to generation that will be self-scheduled in the day-ahead market and, therefore, anticipates making use of that market to clear the majority of its load and generation. The Company expects that its remaining dispatchable resources and residual load will settle in the real-time market. The overall price level and volatility of these new markets cannot be determined at this time; however, the Company expects to employ available risk mitigation mechanisms and its largely firm-priced sources to limit the effects.

     Administrative fees applied by the ISO to transactions are also being changed to reflect greater costs of SMD. The Company believes that in total the administrative costs of SMD will be greater than prior market configurations. Separately, the Company, through VYNPC, is engaged in discussions with Entergy, which owns the Vermont Yankee plant, over transaction settlement procedures, allocation of transaction costs and volumetric measures charges under the SMD.

     Operating reserve requirements are also changing and, in general, the Company expects the new requirements are likely to somewhat raise costs relative to the system operating reserve requirements in place prior to SMD. ISO-New England has also increased the financial assurance requirement for all entities participating in the market based upon each entity's credit rating and current net position. The Company anticipates that additional credit related costs, relative to the pre-SMD market, are likely to be incurred in order to satisfy this requirement.

     The rules requiring load-serving entities to hold generating capacity based upon peak demands in the region are also being revamped. Going forward, this responsibility will be determined by each entity's share of the New England peak load over a trailing annual period. In general, the Region tends to experience its peaks in summer months while the Company's maximum loads tend to occur in the months of December and January. The capacity credit received for generation is also being modified to further account for the observed operating performance of the specific sources. In general, the Company believes that its resources demonstrate operating reliability that is relatively favorable to the population of generators in the region.

      On February 6, 2003, ISO-New England announced that SMD would become operational on March 1, 2003. ISO New England is also working with the region's stakeholders to propose to the FERC a new cost allocation rule that will be used to determine who will pay the costs of upgrades to the regional transmission network once SMD has been implemented. VELCO has a number of network upgrades in the planning stage and the net cost to the Company of any such new investments will be affected by cost allocation rulings by the FERC.

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

Utility If retail competition is implemented in Vermont or in Connecticut Valley's New Hampshire service territory, 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.

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     Historically, electric utility rates in Vermont and New Hampshire 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. 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.

     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.  Also see Note 1 to the Consolidated Financial Statements and Critical Accounting Polices, above.

Interest Rate Risk As of December 31, 2002, the Company has $16.3 million of Industrial Development/Pollution Control bonds outstanding, of which $10.8 million have an interest rate that floats monthly and $5.5 million floats every five years with the short-term credit markets. All other utility debt has a fixed rate. There are no interest lock or swap agreements in place. The Company has $46.3 million of consolidated temporary cash investments as of December 31, 2002, including $24.8 million of non-utility temporary cash investments, of which $14.2 million is related to Catamount. Also see non-utility risk factors below. Interest rate changes could also affect calculations affecting estimated pension and other benefit liabilities, thereby affecting pension and other benefit expenses and potentially requiring contributions to the trusts.

Equity Market Risk As of December 31, 2002, the Company's pension trust holds marketable equity securities in the amount of $34.8 million and its share of the Millstone Unit #3 decommissioning trust, in the amount of $2.3 million. The Company also maintains a variety of insurance policies in a Rabbi Trust, with a current value in the amount of $4.2 million, as of December 31, 2002, to support various supplemental retirement and deferred compensation plans. The current values of certain of these policies are affected by changes in the equity market. Therefore, changes in the equity market could affect pension expense as well as the Millstone Unit #3 decommissioning fund and the Rabbi Trust asset balances.

Credit Risk The Company has $16.9 million of letters of credit, supporting three series of tax-exempt pollution control/industrial development bonds, totaling $16.3 million, of which the earliest series matures in 2009. These letters of credit expire on August 31, 2003 and need to be renewed. Without the support of the letters of credit, the bonds could become due.

     The Company has $10.5 million of first mortgage bonds maturing in the next five years and $75 million of second mortgage bonds that mature on August 1, 2004. It is currently anticipated that all, or a majority of, the debt will be refinanced at maturity. The type, timing and terms of future financing that the Company may need will depend upon its cash needs, the availability of refinancing sources and the prevailing conditions in the financial markets.

     The covenants covering the Company's second mortgage bonds contain limiting restrictions if those bonds receive a debt rating below BBB- from rating agencies. The current ratings of the bonds from both Fitch and Standard & Poor's are BBB- (stable). The limiting characteristics include certain restrictions on investments in non-regulated subsidiaries, the incurrence of indebtedness and the payment of dividends. Restrictions are dependent on meeting both a Fixed Charge Coverage and a Cumulative Cash Flow test. At December 31, 2002, both tests indicate current levels are acceptable.

Inflation The annual rate of inflation, as measured by the Consumer Price Index, was 1.6 percent for 2002, 2.8 percent for 2001 and 3.4 percent for 2000. 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.

Non-Utility 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.  Catamount's future success is dependent on the acceptance of wind power as an energy source by large producers, utilities, and other purchasers of electricity. Historically, the wind energy industry had a reputation for numerous problems relating to the failure of many wind-power generating facilities developed in the early 1980s to perform acceptably. In addition, many potential

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customers believe that wind energy is an unpredictable and inconsistent resource, is uneconomic compared to other sources of power and does not produce stable voltage and frequency. Although Catamount believes that these concerns may be adequately addressed in the near-term, there is no guarantee of wind power acceptance by potential customers as an energy source.

Dependence on Governmental Policies The wind energy industry is highly dependent upon governmental policies and laws enacted to stimulate growth of clean renewable energy through tax credits and other incentive plans, including mandatory purchasing requirements by local utilities of renewable energy, including wind energy. While the trend worldwide is to increase the use of renewable energy sources, there is no assurance that any particular governmental policy or tax credit or incentive program will be continued in any jurisdiction where Catamount conducts business.

     United States The U.S. Congress has enacted a production tax credit, which provides owners of wind energy projects a credit of 1.8 cents/kWh produced by any wind energy project installed and in operation by December 31, 2003. This credit may be earned by such eligible projects for the first 10 years of each project's life. Continued growth of the U.S. wind energy industry depends upon this tax credit being extended beyond December 2003, and depends upon an adequate market of investors who can utilize this credit efficiently. While bills containing extensions for the production tax credit have been introduced in both houses of the U.S. Congress, there is no assurance that such bills will be enacted into law and that the tax credit will be so extended. There are currently 13 U.S. states that have some form of mandatory renewable energy purchase requirements by utilities located in their respective states. Several U.S. states have other incentive and g rant programs to promote renewable energy. There is no assurance that any such program will be extended when each expires and there is no assurance that other states will follow the lead in promoting mandatory purchasing schemes.

     Europe The European Union ("EU") Renewable Energy Directive, formally adopted in September 2001, establishes national targets that would collectively result in renewable energy contributing 12 percent of the gross electricity consumed by the EU's 15 member countries in 2010 and a long-term goal of 22 percent. There can be no assurances as to how EU countries will implement and maintain policies related to the Renewable Energy Directive. Further, revenues generated in Catamount's targeted European markets are expected to be derived from renewable energy electricity purchases, which are currently required by national law. Support for renewable energy could diminish in any or all of these countries, resulting in the repeal of these national laws.

Regulation in the United States The electric utility industry in the U.S. remains highly regulated and subject to energy and environmental laws at the federal, state and local levels. Catamount's operations are currently unregulated by the federal or state electric industry regulators, despite the fact Catamount is a wholly owned subsidiary of the Company. In addition, electric generation projects are subject to federal, state and local laws and administrative regulations, which govern the geographic location, zoning, land use and operation of plants and emissions produced by said plants. There is no guarantee that Catamount's operations will remain unregulated and may be subject to federal, state and local regulations in the future.

Reliance on Third-Party Equipment Vendors Currently less than 10 major wind turbine-generating ("WTG") manufacturers are serving the worldwide wind energy market. In the recent past, several of these manufacturers have been subject to financial difficulties, mergers and industry consolidation. Because customer demand for WTGs fluctuates based upon market conditions, there is no assurance that manufacturing capacity will be available to meet expected increases in demand at any one time. Further, there is no assurance that key components and parts will be available to service WTGs, which could adversely impact Catamount's operations.

Foreign Operations Catamount currently owns investments in the UK and Germany and intends on developing wind energy projects in targeted European countries. Catamount's business may be affected by fluctuations in currency exchange rates, governmental currency controls, changes in various regulatory requirements, political and economic changes and disruptions, difficulties in managing foreign operations, including collections, and possible adverse tax consequences.

Interest Rate Risk Catamount has a variable rate revolving credit/term loan facility. In January 2003, Catamount paid down its outstanding loan by $12.6 million, thereby reducing its exposure to interest rate risk. Catamount also maintains temporary cash investment accounts to meet its liquidity needs. At December 31, 2002, Catamount's temporary cash investments amounted to $14.9 million, which includes a portion used for the January 2003 pay-down of its outstanding loan.

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Credit Exposure Recent events including uncertainties concerning the operations of the wholesale markets and the demise of major wholesale power marketing companies have increased credit exposure in the energy industry and specifically with unregulated energy companies. Obtaining or renewing corporate credit facilities is challenging and there is no guarantee credit will either be extended or renewed. In December 2002, Catamount extended its corporate credit facility for an additional two years.

Impairment or Disposal of Long-Lived Assets On January 1, 2002, the Company adopted SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS No. 144") that replaces SFAS No. 121, which the Company previously adopted. As with SFAS No. 121, SFAS No. 144 requires that any assets, including regulatory assets, that are no longer probable of recovery through future revenues, be revalued based upon undiscounted future cash flows. SFAS No. 144 requires that a rate-regulated enterprise recognize an impairment loss for the amount of costs excluded from recovery. As of December 31, 2002, based upon the regulatory environment within which the Company currently operates, SFAS No. 144 did not have an impact on the Company's regulated businesses. Competitive influences or regulatory developments may impact this status in the future.

Asset Retirement Obligations In August 2001, the Financial Accounting Standards Board ("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 ("ARO") in the period in which it is incurred. The Company has retirement obligations associated with decommissioning related to its investments in nuclear plants, certain of its jointly owned generating plants and certain Catamount investments. The Company adopted SFAS No. 143 on January 1, 2003 as required. The cumulative effect of adopting SFAS No. 143 is not material.

Costs Associated with Exit or Disposal Activities In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities ("SFAS No. 146"), which requires entities to record a liability for costs related to exit or disposal activities when the costs are incurred. Previous accounting guidance required the liability to be recorded at the date of commitment to an exit or disposal plan. This statement applies only to exit activities initiated in 2003 and after. The Company does not expect a material impact on its financial position or results of operations.

Stock-Based Compensation Transition and Disclosure In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation Transition and Disclosure, ("SFAS No. 148") an amendment of SFAS No. 123. SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair-value-based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require more prominent and more frequent disclosures in financial statements about the effects of stock-based compensation. This statement is effective for financial statements for fiscal years ending after December 15, 2002.  The Company adopted the disclosure requirements related to SFAS No. 148 as of December 31, 2002.

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Item 8.    Financial Statements and Supplementary Data.

Index to Financial Statements and Supplementary Data

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

     We have audited the accompanying consolidated balance sheet and statement of capitalization of Central Vermont Public Service Corporation and subsidiaries (the Company) as of December 31, 2002, and the related consolidated statements of income, changes in common stock equity and cash flows for the year then ended December 31, 2002. The financial statements of Central Vermont Public Service Corporation and subsidiaries as of December 31, 2001 and 2000 and for the years then ended were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion, which included an emphasis of a matter paragraph on those financial statements in their report dated February 4, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

     We conducted our audit in accordance with auditing standards generally accepted in the United States of America. 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 audit provides 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 subsidiaries as of December 31, 2002 and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

     As discussed in Note 12, the Company has reached agreement to sell Connecticut Valley Electric Company, its wholly owned subsidiary, to Public Service Company of New Hampshire. The Company believes this sale will render as moot a pending request filed with the Federal Energy Regulatory Commission for an exit fee mechanism to cover the stranded costs resulting from the potential cancellation of the power contract between the Company and Connecticut Valley Electric Company. If the sale is not completed and the power contract is ultimately cancelled, the Company would be required to recognize a loss under this contract of a material amount if it is unable to obtain an order authorizing the recovery of a significant portion of the exit fee, or other appropriate stranded cost mechanism.

Boston, Massachusetts

February 4, 2003

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

     We have audited the accompanying consolidated balance sheets and statements of capitalization of Central Vermont Public Service Corporation and its wholly owned subsidiaries (the Company) as of December 31, 2001 and 2000, and the related consolidated statements of income, changes in common stock equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

     In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Central Vermont Public Service Corporation and its wholly owned subsidiaries as of December 31, 2001 and 2000 and the results of their operations and cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States.

     As discussed in Note 12, the Company has filed with the Federal Energy Regulatory Commission a request for an exit fee mechanism to cover the stranded costs resulting from the potential cancellation of the power contract between the Company and its wholly owned subsidiary Connecticut Valley. If the power contract is ultimately cancelled and the Company is unable to obtain an order authorizing the recovery of a significant portion of the exit fee, or other appropriate stranded cost mechanism, the Company would be required to recognize a loss under this contract of a material amount.

Boston, Massachusetts

February 4, 2002

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CONSOLIDATED STATEMENTS 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 STATEMENTS OF CASH FLOWS
(Dollars in thousands)