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

     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:  $286,210,205 based upon the closing price as of January 30, 2004 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, 2004, there were outstanding 12,050,956 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 4, 2004 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, 13 and 14 of Part III of this Form 10-K.

Form 10-K - 2003

TABLE OF CONTENTS

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Item 1.    Business

     Central Vermont Public Service Corporation (the "Company") makes available free of charge through its Internet Web site, http://www.cvps.com its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after those reports are electronically filed with the Securities and Exchange Commission.  Access to the reports is available from the main page of the Company's Internet Web site through "Investor Relations".  The Company's Corporate Ethics and Conflict of Interest Policy and Corporate Governance Guidelines are also available on our Internet Web site.  Access to these documents is available from the main page of the Company's Internet Web site through "Corporate Governance and Ethics".  Printed copies of these documents are also available upon written request to the Assistant Corporate Secretary at our principal executive offices.

     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 148,164 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 76 percent of total mWh sales for 2003. Sales to the five largest retail customers receiving electric service from the Company during the same period aggregated about 5 percent of the Company's total electric revenues for the year. The Company's resale firm sales accounted for approximately 4 percent and other resale sales which include contract sales, sales to ISO-New England and short-term system capacity sales accounted for approximately 20 percent of total mWh sales for 2003.

     The Company's wholly owned subsidiary, Connecticut Valley Electric Company Inc. ("Connecticut Valley"), incorporated under the laws of New Hampshire on December 9, 1948, distributed and sold electricity in parts of New Hampshire bordering the Connecticut River. It served 10,507 customers in 13 communities in New Hampshire. Connecticut Valley's sales were 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 2003. Sales to its five largest retail customers during the same period aggregated about 16 percent of Connecticut Valley's total electric revenues for 2003. On January 1, 2004, Connecticut Valley completed the sale of substantially all of its plant assets and its franchise to Public Service Company of New Hampshire ("PSNH"). See New Hampshire Retail Rates below for additional information related to the sale.

     The Company owns 50.5 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 2003, the Company's ownership in VELCO changed from 50.6 percent to 50.5 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 58.85 percent of the common stock of Vermont Yankee Nuclear Power Corporation ("Vermont Yankee"). The Company's ownership percentage changed from 33.23 percent to 58.85 percent in the fourth quarter of 2003, related to the buy-back of shares held by minority owners. Vermont Yankee was initially 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, Vermont Yankee completed the sale of its nuclear power plant to Entergy Nuclear Vermont Yankee, LLC ("Entergy"). Vermont Yankee administers 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.

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     The Company's wholly owned subsidiary, 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 the United States and the United Kingdom. Another of its subsidiaries, Eversant Corporation, engages in the sale or rental of electric water heaters through a wholly owned 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, 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. On January 1, 2004, Connecticut Valley completed the sale of substantially all of its plant assets and its franchise to PSNH. See discussion of Discontinued Operations below.

     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.

     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 have been two instances 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 between Springfield and the Company in 1985.

     In 2002, the Town of Rockingham voted to pursue purchasing the Company's distribution facilities, Green Mountain Power's ("GMP") distribution facilities, and USGen's hydroelectric facility located in Bellows Falls. The Company and GMP refused to voluntarily sell their distribution facilities. In November of 2003, the Company was notified that Rockingham intended to obtain their facilities by eminent domain under Title 24 V.S.A. Section 2805. The Company opposed this action as being contrary to Title 30, and on December 23, 2003, was able to obtain a permanent injunction from the Superior Court prohibiting Rockingham from pursuing this course of action. Should Rockingham decide to continue this action it must now proceed to the PSB under Title 30. The Company currently serves approximately 260 customers in Rockingham which customers consume approximately 2.024 megawatt hours annually.

     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 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. The State of Vermont is pursuing a variety of initiatives that are aimed at restructuring the provision of electric service without introducing retail choice. See PART II Item 7, herein, for a discussion of Electric Industry Restructuring, and Wholesale Rates below, for a discussion related to the Company's wholesale electric business.

     The Company recognizes that adequate and timely rate relief is required to maintain its financial strength, particularly since Vermont law does not allow power and fuel costs to be passed to consumers through fuel adjustment clauses. The Company will continue to review costs and request rate increases when warranted.

2000 Retail Rate Case:  The Company's current retail rates are based on a June 26, 2001 PSB Order approving a settlement with the DPS, including a 3.95 percent rate increase effective July 1, 2001. As part of the settlement, the Company also agreed to a $9 million write-off ($5.3 million after-tax) of regulatory assets and a rate freeze through January 1, 2003. The order also ended uncertainty over Hydro-Quebec cost recovery by providing full cost recovery, made the January 1, 1999 temporary rates permanent, allowed the Vermont utility a return on common equity of 11 percent for the year ending June 30, 2002 (capped through January 1, 2004), and created new service quality standards. Lastly, the rate order requires the Company to return up to $16 million to ratepayers if there is a merger, acquisition or asset sale that requires PSB approval.

July 2003 Memorandum of Understanding ("MOU"):  In April 2003, the Company prepared cost of service studies for rate years 2003 and 2004, in accordance with the PSB's approval of the Vermont Yankee sale. The purpose of those filings was to determine whether a rate decrease was warranted in either year as a result of the sale of the Vermont Yankee plant. In July 2003, the Company reached a MOU with the DPS regarding that filing. The agreement concluded that: 1) a rate decrease was not warranted; 2) the Company would decrease its allowed return on common equity from 11 percent to 10.5 percent effective July 1, 2003; 3) any earnings over the allowed cap of 10.5 percent would be applied to reduce deferred charges on the balance sheet; 4) the Company would file a fully allocated cost of service plan and a proposed rate redesign; and 5) the Company agreed to work cooperatively with the DPS to develop and propose an alternative regulation plan.

     Hearings on the MOU were conducted by the PSB in December 2003, and the PSB issued an Order on January 27, 2004 providing conditional approval for the MOU. It included the following significant modifications: 1) that the return on common equity be reduced to 10.25 percent; 2) starting January 1, 2004 the Company would begin new amortizations of deferred charges on the balance sheet at December 31, 2003 of about $2.5 million annually; and 3) that the Company would file with the PSB a proposal to apply the $21 million payment it received from PSNH, in connection with the Connecticut Valley sale, to write down deferred charges.

     The MOU and PSB Order are not binding on the Company. On February 3, 2004, the Company filed a Request for Reconsideration and Clarification. On February 12, the Company filed information with the PSB in response to PSB information requests. The Company has been advised that the PSB will schedule a workshop in March 2004 to review the Company's filing. The MOU and related Request for Reconsideration and Clarification are still in the regulatory process and the Company cannot predict the outcome of that process at this time.

Mandated Earning Cap:  The Vermont utility earnings were above the allowed rate of return on common equity of 11 percent for the 12 months ended December 31, 2003, resulting in a $1.5 million, after-tax, reduction of the Vermont utility's earnings, to stay below the mandated earnings cap. Similarly, in 2002 the Vermont utility earnings were reduced by about $0.4 million, after-tax. The Company recorded related pre-tax regulatory liabilities amounting to about $2.5 million in 2003 and $0.7 million in 2002, which are expected to be used to decrease deferred charges on the balance sheet at December 31, 2003.

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New Hampshire Retail Rates

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

     On December 20, 2002, the NHPUC approved Connecticut Valley's fuel and purchased power rates for 2003, and on December 30, 2002, the Commission approved a Business Profits Tax Adjustment Percentage for 2003. Rates increased 8.5 percent on January 1, 2003.

     On April 16, 2003, the NHPUC approved Connecticut Valley's request for an Interim PPCA to reduce a potential over-collection during the remainder of 2003. As a result, Connecticut Valley's rates decreased 6.3 percent beginning May 1, 2003.

Connecticut Valley Sale: On January 1, 2004, Connecticut Valley completed the sale of substantially all of its plant assets and its franchise to PSNH. As such, Connecticut Valley did not file to change its annual FAC, PPCA and Business Profits Tax Adjustment as it had done in the past.

     The sale resolved all Connecticut Valley restructuring litigation in New Hampshire and the Company's stranded cost litigation at FERC, which is described in more detail in Wholesale Rates below. On January 1, 2004, PSNH paid Connecticut Valley about $30 million, with $9 million of that amount representing the net book value of its plant assets plus certain other adjustments, plus $21 million as provided in the agreements under which the sale was structured. In return, PSNH acquired Connecticut Valley's poles, wires, substations and other facilities, and several independent power obligations, including the Wheelabrator contract.

     The sale resulted in a net gain of approximately $5 million to $7 million which will be recorded in the first quarter of 2004. The gain, net of reserves, is related to the difference between expected sales revenue for the power that the Company formerly sold to Connecticut Valley and estimated sales revenue at market rates, for the years 2004 through 2015. This represents the estimated life of the power contracts that were in place to source the wholesale power contract between the Company and Connecticut Valley. The Company will evaluate a long-term sale of the majority of power previously sold to Connecticut Valley to limit future market price variability.

     The assets and liabilities of Connecticut Valley are classified as held for sale on the Company's Consolidated Balance Sheets, in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, ("SFAS No. 144") and its results of operations are reported as discontinued operations for all periods presented in the Company's Consolidated Income Statements. For presentation purposes, certain of the Company's common corporate costs, which were previously allocated to Connecticut Valley, have been reallocated back to continuing operations to reflect the impact of the sale on continuing operations. These common costs amounted to about $1.3 million in 2003, $1.4 million in 2002 and $1.2 million in 2001, on an after-tax basis. The Company began to present Connecticut Valley as discontinued operations in the second quarter of 2003 based on the NHPUC's approval of the sale. Previously, Connecticut Valley was reported as a separate segment. As a wholly owned subsidiary of the Company, Connecticut Valley's results of operations may not be representative of a stand-alone company.

Wholesale Rates  The Company sold 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 provided for an automatic update of annual capacity rates, as well as a subsequent reconciliation to actual data. For 2003, the Company filed and FERC approved 1) a revenue decrease of $1,266,000, or 10.6 percent, for 2003 power costs; and 2) a reconciliation of 2002 revenues to actual costs which resulted in a refund of $203,000, including interest.

     On January 1, 2004, Connecticut Valley paid the Company $21 million to terminate the wholesale power contract. The sale of Connecticut Valley's plant assets and franchise to PSNH, and the $21 million payment also resolved the Company's outstanding FERC litigation. The stranded cost litigation at FERC was related to its June 1997 request for FERC approval of a transmission rate surcharge to recover stranded costs if Connecticut Valley canceled its wholesale power contract with the Company due to the NHPUC's February 1997 Order in which it told Connecticut Valley to stop buying power from the Company. In December 1997, FERC rejected the proposal, but said it would consider an exit fee if the contract was canceled. A rehearing motion was denied. The Company applied for an exit fee totaling $44.9 million as of December 31, 1997.

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     In October 2002, the Company and NHPUC asked FERC to withhold its final exit fee order so the parties could continue to negotiate a settlement. In October 2003, FERC approved termination of the wholesale power contract and related exit fee proceedings upon completion of the sale.

Wheelabrator Power Contract Connecticut Valley purchased power from several independent power producers, who own qualifying facilities as defined by the Public Utility Regulatory Policies Act of 1978. In 2003 Connecticut Valley bought 38,700 mWh under long-term contracts with these facilities, 94 percent from Wheelabrator Claremont Company, L.P., ("Wheelabrator") which owns a trash-burning generating facility. Connecticut Valley had filed a complaint with FERC related to its concern that Wheelabrator had not been a qualifying facility since it began operation. FERC denied that complaint and later denied an appeal, so Connecticut Valley sought relief from the NHPUC. In April 2002 Connecticut Valley and other parties submitted a settlement to the NHPUC.  The January 1, 2004 sale described above resolved this issue.

     The Company's and Connecticut Valley's energy generation and purchased power required to serve their retail and firm wholesale customers was 2,552,827 mWh for the year ended December 31, 2003. The maximum one-hour integrated demand during that period was 417.2 mW, which occurred on December 2, 2003. The Company's and Connecticut Valley's total energy generation and purchased power in 2003, including that related to all resale customers, was 3,062,471 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, 2003. 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 gas turbines and one diesel-peaking unit with a combined nameplate capability of 28.9 MW.

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     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 1,157 MW nuclear generating facility (see discussion below); Wyman #4, a 615 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 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, 2003, the Company's obligation is approximately 46 percent of the total VJO Power Contract through 2016, which translates to approximately $734 million, on a nominal basis. The average annual amount of capacity that the Company will purchase from January 1, 2004 through October 31, 2012 is approximately 144.2 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 The Company has a 35 percent entitlement in Vermont Yankee output sold by Entergy Nuclear Vermont Yankee, LLC ("Entergy") to Vermont Yankee, through a long-term power purchase contract with Vermont Yankee. One remaining secondary purchaser continues to receive a small percentage of the Company's entitlement. The long-term contracts between Vermont Yankee and the Company and between Vermont Yankee and Entergy became effective on July 31, 2002, the same day that the Vermont Yankee nuclear plant was sold to Entergy. The Company is responsible for the purchase of replacement power to the extent required to serve its load when the plant is not operating due to scheduled or unscheduled outages.

     The purchased power contract ("PPA") in which Vermont Yankee purchases power from Entergy and in turn sells to the Company and other parties includes prices that generally range from 3.9 cents to 4.5 cents per kilowatt-hour through 2012. Effective November 2005, the contract prices are subject to a "low-market adjuster" that protects the current Vermont Yankee entitlement holders, including the Company and its power consumers, if power market prices drop significantly. If the market prices rise, however, contract prices are not adjusted upward. The PPA is expected to result in decreased costs over the life of the PPA when compared to continued ownership of the plant. See PART II Item 8, Note 13 for additional information regarding Vermont Yankee.

Cogeneration/Independent Power Qualifying Facilities The Company receives power from several Independent Power Producers ("IPPs"). These plants use water, biomass and trash as fuel. Most of the power comes through a state-appointed purchasing agent, VEPP Inc. ("VEPPI"), which assigns power to all Vermont utilities under PSB rules. In 2003, the Company received 164,918 mWh under these long-term contracts, including 142,968 mWh

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received through VEPPI. These IPP purchases account for 6.2 percent of the Company's total mWh purchased and 11 percent of purchased power costs. 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, New England Independent System Operator ("ISO-New England"), was established in July 1997, following FERC approval, and immediately assumed responsibility for the management of the New England region's power grid and transmission systems and administering the region's open access tariff. ISO-New England was formed by transferring staff and equipment from NEP OOL 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 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.

     On March 1, 2003, ISO-New England moved to a new market structure referred to as Standard Market Design ("SMD"), a significant step to restructuring the wholesale energy markets in the Northeast. See PART II, Item 7 herein for additional information regarding SMD and Regional Transmission Organizations.

     NEPOOL's peak for the year occurred on August 22, 2003 and totaled 24,762 MW. The Company's peak demand occurred on December 2, 2003 and totaled 417.2 MW; the Company had a reserve margin of approximately 18.9 percent, at the time of this peak.

     The Company engages in short-term purchases and sales in the wholesale markets administered by ISO-New England and with other third parties, primarily in New England, to minimize net power costs and risks to our customers. The Company's long-term power forecast reflects energy amounts in excess of that required to meet load requirements; therefore net power costs are dependent, in part, upon wholesale power market prices. Additionally, the January 1, 2004, sale of Connecticut Valley's assets and termination of its power contract released an average of about 11 MW on-peak and 17 MW off-peak of the Company's power supply mix for future disposition.

     On an hourly basis, power is sold or bought through ISO-New England to balance the Company's resource output and load requirements. From time to time, the Company enters into forward sale transactions in order to reduce volatility of forecasted power costs. The Company may also enter into forward purchase transactions, when its forecasts reflect deficiencies such as scheduled refueling outages at Vermont Yankee. See Part II Item 7, herein.

     The Company is one of several sponsor companies with ownership interests in Maine Yankee, Connecticut Yankee and Yankee Atomic. The Company is responsible for paying its ownership percentage of decommissioning and all other costs for each plant. These companies have permanently shut down generating activities and are conducting decommissioning activities. The Company also has a 1.7303 percent joint-ownership interest in Millstone Unit #3. The Company's obligations related to the eventual decommissioning of the Vermont Yankee plant ceased when the plant was sold to Entergy on July 31, 2002.

Millstone Unit #3 The Company has an external trust dedicated to funding its joint ownership share of future decommissioning for Millstone Unit # 3. Contributions to the Millstone Unit #3 Trust Fund have been suspended based on the lead owner's representation to various regulatory bodies that the Trust Fund, for its share of the plant, exceeded the Nuclear Regulatory Commission's 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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Maine Yankee, Connecticut Yankee and Yankee Atomic  The Company's share of estimated future payments related to the decommissioning of Maine Yankee, Connecticut Yankee and Yankee Atomic, based on current forecasts for each plant, are as follows (dollars in millions):

     Maine Yankee, Connecticut Yankee and Yankee Atomic are seeking recovery of fuel storage related costs stemming from the default of the United States Department of Energy ("DOE") under the 1983 fuel disposal contracts that were mandated by the United States Congress under the High Level Waste Act. These damage claims are now pending in the Federal Court of Claims. The trial is expected to begin in July 2004. The fuel storage related costs associated with the damage claims are included in each company's estimated total obligation, shown in the table above. None of the plants have included any allowance for potential recovery of these claims in their estimates.

     The Company's share of each plant's estimated revenue requirements are reflected in the Company's Consolidated Balance Sheets as regulatory assets or other deferred charges, and nuclear decommissioning liabilities (current and non-current). At December 31, 2003, the Company had regulatory assets of about $7.4 million related to Maine Yankee and $3 million related to Connecticut Yankee. These estimated costs are being collected from the Company's customers through existing retail and wholesale rate tariffs. At December 31, 2003, the Company also had other deferred charges of about $10.3 million related to incremental dismantling costs for Connecticut Yankee and $7.5 million for Yankee Atomic. These amounts are not currently being collected from customers through existing rates. On October 29, 2003, the PSB approved an Accounting Order for treatment of these incremental costs as other deferred charges, to be addressed in its next rate proceeding. The Company will adjust t he associated regulatory assets, other deferred charges and nuclear decommissioning liabilities when revised estimates are provided.

Maine Yankee: The Company has a 2 percent ownership interest in Maine Yankee. Costs billed by Maine Yankee are expected to change due to their October 21, 2003 filing at FERC. Maine Yankee's current billings to sponsor companies are based on their rate case settlement approved by FERC on June 1, 1999 under which costs were to be recovered through October 2008. In that settlement, Maine Yankee agreed to file a FERC rate proceeding with an effective date for new rates no later than January 1, 2004. In the current filing the cost recovery period is proposed to extend to 2010.

Connecticut Yankee: The Company has a 2 percent ownership interest in Connecticut Yankee. Costs currently billed by Connecticut Yankee are based on its most recent FERC-approved rates, which became effective September 1, 2000, for collection through 2007. These amounts are being collected from the Company's customers through existing rates.

     Connecticut Yankee is involved in a contract dispute with Bechtel Power Corporation ("Bechtel"), which resulted in termination of the decommissioning services contract between Connecticut Yankee and Bechtel. This is a commercial contract dispute regarding Bechtel's performance; it is not related to safety, security or workmanship issues. As a result of contract termination, on July 14, 2003, Connecticut Yankee became the general contractor for the decommissioning.

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     On June 23, 2003, Bechtel responded to the notice of termination by filing a complaint for breach of contract, misrepresentation, and bad faith, in Connecticut Superior Court. After the contract termination, Bechtel amended its complaint to allege additional contract breaches (including wrongful termination) by Connecticut Yankee.

     On August 22, 2003, Connecticut Yankee formally denied the allegations of Bechtel's amended complaint and filed a counterclaim. It alleges various material breaches of contract that justified Bechtel's termination, along with misrepresentation and bad faith. It also requests that Bechtel be found responsible for project costs in excess of Bechtel's unpaid contract balance, and for other damages. The lawsuit has been assigned to the Complex Litigation Docket and has been set for a jury trial beginning May 4, 2006. Connecticut Yankee also notified Bechtel's surety of its intention to file a claim under the performance bond.

     At Connecticut Yankees' December 2003 Board of Directors meeting, the Board endorsed an updated estimate of the costs for the plant's decommissioning project. This updated cost estimate referred to as the "2003 Estimate" of approximately $823 million, covers the time period 2000 through 2023 and represents an aggregate increase of approximately $413 million in nominal dollars over the cost estimate in its 2000 FERC rate case settlement, which covered the same time period. It also includes increased costs from a November 2002 updated estimate which were related to projected costs of spent fuel storage, security, and liability and property insurance. The 2003 Estimate represents an increase of about $389 million in 2003 dollars. Prior to the approval of the cost estimate in the 2000 FERC settlement, Connecticut Yankee had also incurred about $184 million for decommissioning costs in the 1997 - 1999 timeframe.

     The 2003 Estimate is still undergoing review; it reflects the fact that Connecticut Yankee is now directly managing the work (self performing) to complete decommissioning of the plant following the default termination of Bechtel as described above. Connecticut Yankee intends to update the estimate based on additional information when available including the results of competitive bidding of project work such as demolition. The 2003 Estimate does not include any allowance for relief of the Bechtel contract dispute or the DOE damage claim described above.

     Connecticut Yankee is also beginning the preparation of a rate case application that is required to be filed with FERC by July 1, 2004 under the terms of its 2000 FERC rate case settlement. While Connecticut Yankee has not determined the relief it will seek in the forthcoming application, it anticipates that annual decommissioning collections would have to be increased significantly, beginning January 2005, to support anticipated project cash flow over the next several years and to fund long-term fuel storage through 2023.

     The Company's estimated aggregate obligation related to Connecticut Yankee is about $13.3 million. The timing, amount and outcome of these filings cannot be predicted at this time. The Company believes its share of Connecticut Yankee's decommissioning costs are probable of recovery in future rate proceedings.

Yankee Atomic: The Company has a 3.5 percent ownership interest in Yankee Atomic. Billings to the Company ended in July 2000 based on Yankee Atomic's determination that it had collected sufficient funds to complete the decommissioning effort. The Company is not currently collecting Yankee Atomic costs in retail rates.

     In late 2002, Yankee Atomic revised its cost estimate for decommissioning the plant, reflecting an increase of about $190 million over prior estimates utilized by FERC. The increase was attributable to increases in projected costs of spent fuel storage, security, and liability and property insurance. In April 2003, Yankee Atomic filed with FERC for new rates to collect these costs from sponsor companies. FERC approved the resumption of billings starting June 2003 for a recovery period through 2010, subject to refund. The Company expects its share of these costs will be recoverable in future rates. In 2003, Yankee Atomic's billings to the Company amounted to about $1.1 million. Based on a PSB-approved accounting order, the Company is deferring these costs.

The Price-Anderson Act ("Act") currently limits public liability from a single incident at a nuclear power plant to approximately $10 billion. This protection consists of two levels. The primary level provides liability insurance coverage of $300 million. If this amount is not sufficient to cover claims arising from an accident, the second level, referred to as secondary financial protection, applies. For the second level each nuclear plant must pay a retrospective premium, equal to its proportionate share of the excess loss, up to a maximum of $100.6 million per reactor per incident, limited to a maximum annual assessment of $10 million. 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, and expired in August 2002. Amendments to the Act were included in the Energy Policy Act of 2003, which was not passed. However, liability coverage purchased by existing commercial nuclear power plants under the Act is not

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affected by the expiration date. Currently, based on its joint-ownership interest in Millstone Unit #3, the Company could become liable for about $0.2 million of such maximum assessment per incident per year. The Maine Yankee, Connecticut Yankee and Yankee Atomic plants have received exemptions from participating in the secondary financial protection program under the Act. The Company's obligations under this Act for Vermont Yankee ended with the July 2002 sale of the plant.

     VELCO engages in the operation of a high-voltage transmission system, which interconnects electric utilities in the State including 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 50.5 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 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, 31.45 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.

     At this time, much of the cost of New England's existing and new high-voltage transmission system (115 kV looped facilities) are shared by all New England utilities. VELCO is planning several significant upgrades, which have been approved by the New England Power Pool for shared cost treatment. Vermont has traditionally been a significantly higher than average transmission cost jurisdiction. The new approach is advantageous to the Company's cost and reliability in providing service to its customers because our load share is a small fraction of total New England load, and the facilities VELCO is planning improve both the reliability and efficiency (i.e., losses and congestion) of the transmission network. We will pay a share of such projects elsewhere in New England but the net economic effect is expected to be beneficial, and better reliability elsewhere in the region benefits Vermont's reliability because of the highly integrated nature of New England's high voltage netw ork. However, the cost of other future transmission facilities that do not qualify for cost sharing will be charged only to the requesting entity and our share of such costs will be affected by FERC approved cost-allocation rulings contained in VELCO and the Company's tariffs and agreements. See Part II Item 7, herein.

     At December 31, 2003, VELCO has authorized 92,000 shares of Class B common stock, $100 par value, of which 60,000 shares were outstanding; 20,000 shares of Class C common stock, $100 par value, of which 19,901 were outstanding; and 125,000 shares of Class C preferred stock, $100 par value, of which 97,068 shares were outstanding. In addition, three issues of First Mortgage Bonds, aggregating $50,341,000 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, 2003. The issuance of bonds under the VELCO Indenture is unlimited in amount but is subject to certain restrictions.

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     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.

     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 50.5 percent of VELCO's outstanding common stock, the Four-Party Agreement does not provide the Company ability to exercise control over VELCO.

     In connection with importing 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, 2003) 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 representative, has entered into a similar agreement with New Eng land 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, 2003 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 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 maximum capacity of the Hydro-Quebec 450 kV DC facilities from 690 MW to 2000 MW and extended the Phase I line from Comerford, New Hampshire to Sandy Pond, Massachusetts. The Company uses this transmission path to deliver a portion of the Company's long-term Hydro-Quebec firm power contract. 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 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.

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     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 deferral of transmission and distribution projects, known as Distributed Utility Planning ("DUP"). 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 DUP was filed by the parties in Docket No. 6290 as a Memorandum of Understanding, which was approved by the PSB on January 15, 2003. It 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) continued collaboration of the parties to update the rules as necessary and to share information; and 4) an ongoing collaborative for a number of area specific collaboratives ("ASC") to examine resource investment options for potentially constraine d 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 the United States and United Kingdom. Another of its subsidiaries, Eversant Corporation, engages in the sale or rental of electric water heaters through a wholly owned 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. On December 31, 2003 the Company and its wholly owned subsidiaries including Catamount, employed 535 persons, of which 217 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.

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

     The Company's capital expenditures totaled approximately $15 million in 2003, $13.9 million in 2002 and $16.1 million in 2001. The Company's five-year capital expenditures for the Vermont utility business are expected to range from approximately $85 million to $95 million for the years 2004 through 2008. 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.

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

     Mr. 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; Assistant Vice President Human Resources and Strategic Planning from May 1998 to May 2000; and, Vice President - Human Resources and Strategic Planning from May 2000 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.

     Ms. 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. Ms. 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. and Senior Vice President and Chief Financial Officer of Catamount Energy Corporation.

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     Mr. Kraus joined the Company in 1981. Prior to being elected to his present position of Senior Vice President Engineering and Operations, he served as Corporate Secretary and General Counsel commencing in 1994; Vice President, Corporate Secretary, and General Counsel commencing in 1996; Senior Vice President, Corporate Secretary, and General Counsel commencing in 1999; Senior Vice President Customer Service, Secretary, and General Counsel commencing in 2001; and, Senior Vice President Engineering and Operations, General Counsel, and Secretary from May 2003 until November 2003. Mr. Kraus serves as Director 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 Engineering and Operations for the following CVPS subsidiaries: Conn ecticut Valley Electric Company Inc.

     Mr. Rocheleau joined the Company in November 2003 as Senior Vice President for Legal and Public Affairs, and Corporate Secretary. Prior to joining the Company, he served as Director and Attorney at Law from 1992 to 2003 with Downs Rachlin Martin, PLLC. Mr. Rocheleau also serves as Senior Vice President and General Counsel for Catamount Energy Corporation, 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 617 miles of overhead transmission lines, about 7,826 miles of overhead distribution lines and about 339 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 On January 1, 2004, Connecticut Valley completed the sale of substantially all of its plant assets and its franchise to PSNH. Connecticut Valley's electric properties consisted of two principal systems in New Hampshire which are not interconnected; each system, however, is connected directly with facilities of the Company.

     The electric systems of Connecticut Valley included about two miles of transmission lines, about 446 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.

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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 its financial position or the results of operations, 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 2003.

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

     The table below shows the high and low sales price of the Company's Common Stock, as reported on the NYSE composite tape by The Wall Street Journal, for each quarterly period during the last two years as follows:

     (b) As of December 31, 2003, there were 8,720 holders of the Company's Common Stock, $6 par value.

     (c) Common Stock dividends have been declared quarterly. Cash dividends of $.22 per share were paid for all quarters of 2002 and 2003.

     So long as any Senior Preferred Stock is outstanding, except as otherwise authorized by vote of two-thirds of 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 above are used herein in the sense as defined in subdivision 8A of the Company's Articles of Association; such definitions are based upon the unconsolidated financial statements of the Company. As of December 31, 2003, the Common Stock Equity of the unconsolidated Company was 58.4 percent of total capitalization.

      Several of the Company's indentures relating to its First Mortgage Bonds contain certain restrictions on the payment of cash dividends on capital stock and other Restricted Payments (as defined). The most restrictive of these provisions limit the payment of cash dividends and other Restricted Payments to Net Income of the Company (as defined) for the period commencing on January 1, 2001 up to and including the month next preceding the month in which such Restricted Payment is to be declared or made, plus approximately $77.6 million. The defined terms identified above are used herein in the sense as defined in Article 1 Section 18 of the Forty-Second Supplemental Indenture dated June 11, 2001; such definitions are based upon the unconsolidated financial statements of the Company. As of December 31, 2003, $88 million was available for such Restricted Payments.

     Under the Company's Second Mortgage Indenture, certain restrictions on the payment of cash dividends on capital stock, other Restricted Payments (as defined) and Restricted Investments (as defined) would become effective if the Company's Second Mortgage Bonds are rated below investment grade. The defined terms identified above are used herein in the sense as defined in Article III Section 3.06 of the Second Supplemental Indenture dated December 1, 1999; such definitions are based upon the unconsolidated financial statements of the Company. Under the most restrictive of these provisions, $5.8 million was available for such Restricted Payments and Restricted Investments at December 31, 2003. For additional information regarding dividend payment level and dividend restrictions see Item 8 herein.

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     (d) The information required by this item is incorporated herein by reference to the Proxy Statement of the Company for the 2004 Annual Meeting of Stockholders. Definitive proxy materials will be filed with the Securities and Exchange Commission pursuant to Regulation 14A on or about March 26, 2004.

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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.

In this section we discuss the general financial condition and results of operations for Central Vermont Public Service Corporation (the "Company" or "we" or "our" or "us") and its subsidiaries. Certain factors that may impact future operations are also discussed. Our discussion and analysis is based on, and should be read in conjunction with, the accompanying Consolidated Financial Statements.

Forward-looking statements  Statements contained in this report that are not historical fact are forward-looking statements intended to qualify for the safe-harbors from liability established by the Private Securities Litigation Reform Act of 1995. Whenever used in this report, the words "estimate," "expect," "believe," or similar expressions are intended to identify such forward-looking statements. Forward-looking statements 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 upon, among other things, the actions of regulators, performance of the Vermont Yankee nuclear power plant, effects of and changes in weather and economic conditions, volatility in wholesale power markets, our ability to maintain our current credit ratings, performance of our unregulated businesses, and other considerations such as the operations of ISO-New England, changes in the cost or availability of capital, authoritative accounting guidance, and the effect of the volatility in the equity markets on pension benefit and other costs. We cannot predict the outcome of any of these matters; accordingly, there can be no assurance that such indicated results will be realized. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise.

COMPANY OVERVIEW

     We are a Vermont-based electric utility that transmits, distributes and sells electricity, and invests in renewable and independent power projects. We are regulated by the Vermont Public Service Board ("PSB"), the New Hampshire Public Utilities Commission ("NHPUC"), the Connecticut Department of Public Utility and Control and the Federal Energy Regulatory Commission ("FERC"), with respect to rates charged for service, accounting, financing and other matters pertaining to regulated operations. On January 1, 2004, our wholly owned regulated subsidiary, Connecticut Valley Electric Company, Inc. ("Connecticut Valley"), sold its plant assets and franchise to Public Service Company of New Hampshire ("PSNH"). Prior to the sale, Connecticut Valley distributed and sold electricity in New Hampshire. Our wholly owned unregulated subsidiaries include: Catamount Energy Corporation ("Catamount"), which invests primarily in wind energy projects in the United States and Unit ed Kingdom; and Eversant Corporation ("Eversant"), which operates a rental water heater business through its subsidiary, SmartEnergy Water Heating Services, Inc.

     The Vermont utility operation is our core business. Our retail rates are set by the PSB in conjunction with Vermont's consumer advocate, the Vermont Department of Public Service ("DPS"). Retail rates are designed to recover our costs of service and provide an allowed rate of return on common equity, which, based on our July 2001 rate case settlement, was capped at 11 percent for 2002 and 2003. While Vermont does not have a fuel or power adjustment clause, it is customary for the PSB to approve deferral of extraordinary costs incurred that might normally be expensed by unregulated businesses, in order to match these expenses with future revenues.

     As a regulated electric utility we have an exclusive right to serve customers in our service territory, which can generally be expected to result in relatively stable earnings streams. However, the ability to increase our customer base is limited to growth within the service territory, which has been flat for several years. Given the nature of our customer base, weather and economic conditions are factors that can significantly affect our retail sales revenue. We currently have sufficient power resources to meet our forecasted load requirements, mostly through long-term power contracts. The sale of Connecticut Valley's assets, discussed below, has made available an additional 11 MW on-peak and 17 MW off-peak of our power supply mix for disposition. We sell our excess power in the wholesale markets administered by ISO-New England or to third parties in New England. Such sales help to mitigate our overall power costs; but wholesale power market volatility can affect these mi tigation efforts.

     Vermont regulatory issues that remain unresolved are critically important to our business and a great deal of time is being spent to resolve those matters. In that regard, our top priority is the outstanding Memorandum of Understanding ("MOU") that is discussed in more detail below. In addition to the MOU, there are several State initiatives that could, over time, shift utility regulation away from cost-based regulation. These are discussed in Electric Industry Restructuring below.

     In the fourth quarter of 2003, we received $14.3 million representing our share of cash proceeds related to the July 2002 sale of the Vermont Yankee nuclear power plant. The sale significantly improved our risk profile relative to generation given that we no longer bear the risks and costs associated with running the plant or the eventual decommissioning of the plant. On January 1, 2004, we received approximately $30 million related to the sale of

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Connecticut Valley's plant assets and franchise, described in Discontinued Operations below. The sale, which became effective that day, resolved all Connecticut Valley restructuring litigation in New Hampshire and our stranded cost litigation at the FERC.

     We are currently considering investment alternatives for these cash proceeds. The Vermont utility continues to generate sufficient cash flow to support ongoing operations. While Catamount has sufficient cash flow to cover its operating expenses, additional project investments will require financing or additional funding by the Company. Catamount is also seeking investors and partners to co-invest in the development, ownership and acquisition of projects.

     Our Second Mortgage Bonds of $75 million mature on August 1, 2004. We are considering alternative refinancing arrangements. Currently, we intend to and have the ability to refinance the $75 million at maturity. The outcome of the MOU and perception of the 'regulatory environment' by the financial community may impact the terms and conditions associated with the refinanced debt.

VERMONT RETAIL RATES
     Our current retail rates are based on a June 26, 2001 PSB Order approving a settlement with the DPS, which provided for, among other things, a 3.95 percent rate increase effective July 1, 2001. As part of the settlement, we also agreed to a $9 million write-off ($5.3 million after-tax) of regulatory assets and a rate freeze through January 1, 2003. The Order also: 1) ended uncertainty over Hydro-Quebec cost recovery by providing full cost recovery; 2) made the January 1, 1999 temporary rates permanent; 3) allowed a return on common equity of 11 percent for the year ending June 30, 2002 (capped through January 1, 2004); and 4) created new service quality standards. We are also required to return up to $16 million to ratepayers if there is a merger, acquisition or asset sale by the Company that requires PSB approval.

     In April 2003, we were required to prepare cost of service studies for rate years 2003 and 2004, in accordance with the PSB's approval of the Vermont Yankee sale. The purpose of those filings was to determine whether a rate decrease was warranted in either year as a result of the sale of the Vermont Yankee plant. In July 2003, we agreed to a MOU with the DPS regarding that filing. The agreement concluded that: 1) a rate decrease was not warranted; 2) we would decrease our allowed return on common equity from 11 percent to 10.5 percent effective July 1, 2003; 3) any earnings over the allowed cap of 10.5 percent would be applied to reduce deferred charges on the balance sheet; 4) we would file a fully allocated cost of service plan and a proposed rate redesign; and 5) we would agree to work cooperatively with the DPS to develop and propose an alternative regulation plan.

     Hearings on the MOU were conducted by the PSB in December 2003, and the PSB issued an Order on January 27, 2004 providing conditional approval for the MOU. It included the following significant modifications: 1) that the return on common equity be reduced to 10.25 percent; 2) starting January 1, 2004 we would begin new amortizations of deferred charges on the balance sheet at December 31, 2003 of about $2.5 million annually; and 3) that we would file with the PSB a proposal to apply the $21 million payment we received from PSNH, in connection with the Connecticut Valley sale, to write down deferred charges.

     On February 3, 2004, we filed a Request for Reconsideration and Clarification of that Order. On February 12, 2004, we filed information with the PSB in response to PSB information requests. We have been advised that the PSB will schedule a workshop in March 2004 to review our filing. The MOU and related Request are still in the regulatory process and we cannot predict how it will be resolved at this time. However, if the outstanding MOU issues cannot be successfully resolved, it may result in a formal rate investigation commencing in 2004.

ELECTRIC INDUSTRY RESTRUCTURING

     The State of Vermont is pursuing a variety of initiatives that are aimed at restructuring the provision of electric service without introducing retail choice. The following discussion highlights three initiatives of potential significance.

• The possible introduction of a mandatory Renewable Portfolio Standard ("RPS") that could require us to purchase certain amounts of our energy supply requirement from new renewable resources. We cannot determine whether, or if, a mandatory RPS will ultimately be adopted or required in Vermont. If the RPS proposed by the PSB were to be adopted, it would not require any changes in our power supply portfolio until January 1, 2013.

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• The authorization of utility sponsored renewable pricing programs to permit customers to voluntarily elect to either purchase all or part of their electric energy from renewable sources; or cause the purchase and retirement of tradable renewable energy credits on the participating customer's behalf. In either case, the purpose of such pricing programs is to increase the utility's reliance on renewable sources of energy beyond those the utility would otherwise be required to provide in accordance with its Integrated Resource Plan as approved by the PSB. At this time, we are finalizing the terms of the renewable pricing program that we will file with the PSB for approval. The program will likely be priced in the form of a premium relative to the tariff that would otherwise apply. The premium would be cost-based so that it reasonably reflects the difference between acquiring the renewable energy and our alternative cost of power. The program will require that any costs of power in excess of our altern ative cost of power will be borne solely by those customers who elect to participate in the renewable pricing program.
• The authorization of alternative forms of regulation for electric utilities that, besides other criteria, establish a reasonably balanced system of risks and rewards that encourages the utility to operate as efficiently as possible. The PSB may approve an alternative regulation plan only if it finds that the plan will not have an adverse impact on our eligibility for rate-regulated accounting in accordance with accounting principles generally accepted in the United States of America ("GAAP") and reasonably preserves the availability of equity and debt capital resources to us on favorable terms and conditions.
  

Regulatory Risk In July 2003, we agreed to a MOU with the DPS described in more detail above. On January 27, 2004, the PSB issued its Order providing conditional approval for the MOU. The MOU and related issues are still pending. If the outstanding MOU issues cannot be successfully resolved, it may result in a formal rate investigation commencing in 2004.

     Historically, electric utility rates in Vermont have been based on a utility's costs of service. As a result, electric utilities are subject to certain accounting standards that apply only to regulated businesses. Statement of Financial Accounting Standards ("SFAS") No. 71, Accounting for the Effects of Certain Types of Regulation ("SFAS No. 71") allows regulated entities, including the Company, 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.

     We believe the Company currently complies with the provisions of SFAS No. 71 for our regulated Vermont service territory and FERC-regulated wholesale businesses.  If we determine the Company no longer meets the criteria under SFAS No. 71, the accounting impact would be an extraordinary charge to operations of about $41.8 million on a pre-tax basis as of December 31, 2003, assuming no stranded cost recovery would be allowed through a rate mechanism.

     If retail competition is implemented in our Vermont service territory, we are unable to predict the impact on our revenues, our 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.

Wholesale Power Market Risk Our material power supply contracts and arrangements are principally with Hydro-Quebec and Vermont Yankee Nuclear Power Corporation ("Vermont Yankee"). These contracts support about 90 percent of our total annual energy (mWh) purchases. Our exposure to market price volatility is limited for power supply purchases given that our long-term power forecast reflects energy amounts in excess of that required to meet load requirements. However, if one or both of these sources becomes unavailable for an extended period of time we would be subject to wholesale power price volatility and that amount could be material. Additionally, we rely on the sale of our excess power to help mitigate our overall net power costs. The volatility of wholesale power market prices can impact these mitigation efforts.

     We also continue to monitor, and adapt to, changes to New England wholesale power markets and open access transmission systems. Related to the wholesale power markets, in March 2003, ISO-New England implemented Standard Market Design ("SMD"), a significant step to restructuring the wholesale energy markets in the Northeast. The move to regional transmission organizations ("RTO") also continues. SMD has impacted wholesale power prices, related to short-term sales and purchases as well as the costs of our owned generation. Although we expect that a transition to RTO will impact our transmission costs, we are not able to predict the nature of that impact.

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Interest Rate Risk As of December 31, 2003, we have $16.3 million of Industrial Development/Pollution Control bonds outstanding, of which $10.8 million have an interest rate that floats monthly with the short-term credit markets and $5.5 million that floats every five years with comparable credit markets. All other utility debt has a fixed rate. There are no interest lock or swap agreements in place. We have $55.2 million of consolidated temporary cash investments as of December 31, 2003, including $12.4 million of non-utility temporary cash investments. Interest rate changes could also impact calculations related to estimated pension and other benefit liabilities, affecting pension and other benefit expenses and potentially requiring contributions to the trusts.

Equity Market Risk As of December 31, 2003, our pension trust held marketable equity securities in the amount of $42.5 million and our Millstone Unit #3 decommissioning trust held marketable equity securities of $3.2 million. We also maintain a variety of insurance policies in a Rabbi Trust with a current value of $5.2 million to support various supplemental retirement and deferred compensation plans. The current values of certain policies are affected by changes in the equity market.

Credit Risk   We have $16.9 million of letters of credit expiring on November 30, 2004. These letters of credit support three series of Industrial Development/Pollution Control Bonds, totaling $16.3 million. These letters of credit are secured by a first mortgage lien on the same collateral supporting our First Mortgage Bonds.

     Based on outstanding debt at December 31, 2003, the amount of utility long-term debt maturities and sinking fund requirements is $75 million for the year 2004 related to our Second Mortgage Bonds, which mature on August 1, 2004. We are considering alternative refinancing arrangements. Currently, we intend to and have the ability to refinance the $75 million at maturity. No payments are due on long-term debt for 2005 through 2007. The 8.3 percent Dividend Series Preferred Stock is redeemable at par through a mandatory sinking fund of $1 million annually. In the fourth quarter of 2003, we recorded $2 million in Restricted Cash related to a December 31, 2003 payment to the Transfer Agent for the $1 million mandatory sinking fund payment for 2004 and a $1 million optional payment. The payment to the Preferred Shareholders was made effective January 1, 2004.

     The covenants covering our Second Mortgage Bonds contain limiting restrictions if those bonds receive a debt rating below BBB- from rating agencies. The current ratings of the bonds are BBB- (stable) from Standard & Poor's and BBB (stable) from Fitch. The limiting characteristics include, but are not limited to, certain restrictions on investments in unregulated subsidiaries, the incurrence of indebtedness and the payment of dividends. These restrictions are dependent on meeting both a Fixed Charge Coverage and a Cumulative Cash Flow test, and we are currently in compliance with both calculations.

Inflation The annual rate of inflation, as measured by the Consumer Price Index, was 2.3 percent for 2003, 1.6 percent for 2002 and 2.8 percent for 2001. Our revenues are based on rate regulation that generally recognizes only historical costs; therefore, inflation continues to have an impact on most aspects of the business.

Unregulated Business  In 2001, Catamount undertook a comprehensive strategic review of its operations. As a result, Catamount 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. In addition, many potential 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. There is no guarantee of wind power acceptance by potential customers as an energy source. The following highlights the wind-related risks that we believe are most critical to Catamount:

• Wind Resource and Weather Pattern Risks - The generation of electricity by wind energy projects is highly dependent on site wind conditions. Although wind energy projects are developed with careful review of available historic wind and weather patterns at a particular site, there is no assurance that Catamount can accurately forecast future long-term wind resource at any one site. In addition, average wind speeds and resource can vary widely in any year, resulting in significant annual revenue variability.

• Power Purchase Agreement Risk - Catamount will only develop or co-develop wind power projects that have power purchase agreements with acceptable third parties in place. The increased use of competitive bidding procedures has made obtaining power purchase agreements with utilities more competitive. Competitive bidding generally has reduced the price utilities pay independent power producers, which, in turn, reduces the profitability of many independent power projects.

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• Wind Turbine Generator Technology Risk - The wind turbine generators ("WTGs") of the size Catamount intends to utilize have only been commercially available for two to three years. Long-term reliability of this equipment has yet to be proven. Wind turbine technology is rapidly changing with WTGs' growth in size and rated output every year. Problems with key components in newer turbine models without long track records could result in unexpected availability losses, increased and unbudgeted maintenance and repair costs, and lack of electric production affecting revenue generations. Wind energy projects typically consist of many WTGs of one particular make and model. Therefore, any failure of a key component could result in serial failures of such component throughout the wind energy project, resulting in significantly diminished revenues and materially increased maintenance and repair costs.

• 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.

Credit Risk  Recent events including uncertainties concerning operations of wholesale markets and demise of major wholesale power marketing companies have increased credit exposure in the energy industry, most notably for 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 to November 2004. In February 2004, Catamount notified the lender of its intent to terminate the credit facility. The termination is effective 90 days after notification to the lender. Catamount is currently soliciting proposals from selected financial institutions for corporate and/or development credit facilities that will meet its business needs. Catamount cannot predict whether it will be able to ultimately solicit and enter into an appropriately priced corporate and/or development credit facility.

Capital Requirements  Catamount will require additional capital to pursue its business plan. Catamount is seeking investors and partners to co-invest in the development, ownership and acquisition of projects. There can be no assurance that Catamount will be successful in securing a partner or obtaining additional funding from the Company.

DISCONTINUED OPERATIONS

     On January 1, 2004, Connecticut Valley completed the sale of substantially all of its plant assets and its franchise to PSNH. The sale resolved all Connecticut Valley restructuring litigation in New Hampshire and our stranded cost litigation at FERC. See FERC Exit Fee Proceedings below for additional information.

     On January 1, 2004, PSNH paid Connecticut Valley about $30 million, with $9 million of that amount representing the net book value of its plant assets plus certain other adjustments, plus $21 million as provided in the agreements under which the sale was structured. In return, PSNH acquired Connecticut Valley's poles, wires, substations and other facilities, and several independent power obligations, including the Wheelabrator contract.

     The sale resulted in a net gain of approximately $5 million to $7 million which will be recorded in the first quarter of 2004. The gain, net of reserves, is related to the difference between expected sales revenue for the power that we formerly sold to Connecticut Valley and estimated sales revenue at market rates, for the years 2004 through 2015. This represents the estimated life of the power contracts that were in place to source the wholesale power contract between the Company and Connecticut Valley. We will evaluate a long-term sale of the majority of power previously sold to Connecticut Valley to limit future market price variability.

     The assets and liabilities of Connecticut Valley are classified as held for sale on the accompanying Consolidated Balance Sheets, in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, ("SFAS No. 144") and its results of operations are reported as discontinued operations for all periods presented in the accompanying Consolidated Income Statements. For presentation purposes, certain of our common corporate costs, which were previously allocated to Connecticut Valley, have been reallocated back to continuing operations to reflect the impact of the sale on continuing operations. These common costs amounted to about $1.3 million in 2003, $1.4 million in 2002 and $1.2 million in 2001, on an after-tax basis. We began to present Connecticut Valley as discontinued operations in the second quarter of 2003 based on the NHPUC's approval of the sale. Previously, Connecticut Valley was reported as a separate segment.

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     As a wholly owned subsidiary of the Company, Connecticut Valley's results of operations may not be representative of a stand-alone company. Summarized financial information related to Connecticut Valley, including the reallocation of certain corporate common costs, reflecting Management's best estimate of impacts of the Connecticut Valley sale, are shown in the tables below.

     Summarized results of operations of the discontinued operations are as follows (dollars in thousands):

     The major classes of Connecticut Valley's assets and liabilities reported as held for sale on the Consolidated Balance Sheets are as follows (dollars in thousands):

FERC Exit Fee Proceedings
     The Company's stranded cost litigation at FERC was related to its June 1997 request for FERC approval of a transmission rate surcharge to recover stranded costs if Connecticut Valley canceled its wholesale power contract with the Company due to the NHPUC's February 1997 Order in which it told Connecticut Valley to stop buying power from the Company. In December 1997, FERC rejected the proposal, but said it would consider an exit fee if the contract was canceled. A rehearing motion was denied. We applied for an exit fee totaling $44.9 million as of December 31, 1997.

     In October 2002, the Company and NHPUC asked FERC to withhold its final exit fee order so the parties could continue to negotiate a settlement. In October 2003, FERC approved termination of the wholesale power contract and related exit fee proceedings upon completion of the sale. The sale of Connecticut Valley's plant assets and franchise to PSNH, and Connecticut Valley's $21 million payment to the Company to terminate the wholesale power contract resolved this FERC litigation.

Wheelabrator Power Contract Connecticut Valley purchased power from several independent power producers, which own qualifying facilities as defined by the Public Utility Regulatory Policies Act of 1978. In 2003 Connecticut Valley bought 38,700 mWh under long-term contracts with these facilities, 94 percent from Wheelabrator Claremont Company, L.P., ("Wheelabrator") which owns a trash-burning generating facility. Connecticut Valley had filed a complaint with FERC related to its concern that Wheelabrator had not been a qualifying facility since it began operation. FERC denied that complaint and later denied an appeal, so Connecticut Valley sought relief from the NHPUC. In April 2002 Connecticut Valley and other parties submitted a settlement to the NHPUC.

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     As a result of the January 1, 2004 sale described above, PSNH acquired Connecticut Valley's independent power obligations, including the Wheelabrator contract, thus resolving this issue.

LIQUIDITY AND CAPITAL RESOURCES

     At December 31, 2003, we had cash and cash equivalents of $58 million and working capital of $70 million. During 2003 cash and cash equivalents increased $10 million, reflecting net cash provided by operating activities of $46 million. Net cash used by investing activities amounted to $7.9 million mostly for construction expenditures, partially offset by the Vermont Yankee sale proceeds received in 2003. Net cash used in financing activities was $27.4 million, mainly related to retirement of long-term debt and dividends paid on common and preferred stock. We also used $12.6 million of restricted cash to reduce non-utility long-term debt and had restricted cash of $2 million related to our redeemable preferred stock that was paid in January 2004.

     At December 31, 2002, we had cash and cash equivalents of $48 million and working capital of $51 million. We ended 2001 with $45 million in cash and cash equivalents and $51 million in working capital. During 2002 cash and cash equivalents increased $2 million, reflecting net cash provided by operations of $43 million and net cash used by investing activities of $1.4 million, representing proceeds from sales of non-utility assets, offset by construction expenditures. Net cash used in financing activities was $38.4 million mainly for retirement of long-term debt and preferred stock, and dividends paid on common and preferred stock. We also had restricted cash of $12.6 million related to scheduled retirement of non-utility long-term debt in 2003.

     In the fourth quarter of 2003, we received $14.3 million related to the July 2002 sale of the Vermont Yankee nuclear power plant. On January 1, 2004, we received about $30 million related to the sale of Connecticut Valley's plant assets and franchise. We are currently considering investment alternatives for these cash proceeds. One such opportunity would be to increase our equity ownership in Vermont Electric Power Corporation, Inc. ("VELCO") from 10 percent up to 25 percent, and participate in its planned transmission upgrades, with construction scheduled to begin in late 2004 and extending through 2007. Our current common stock ownership percentage in VELCO is 50.5 percent. While Catamount has sufficient cash flow to cover its ongoing operating expenses, additional project investments will require financing or additional funding on the Company's part. Catamount is also seeking investors and partners to co-invest in the development, ownership and acquisition of projects.< BR>
     We believe that cash on hand and cash flow from operations will be sufficient to fund our business for the foreseeable future. Material risks to cash flow from operations include: loss of retail sales revenue from unusual weather, slower-than-anticipated load growth and unfavorable economic conditions, and increases in net power costs largely due to lower-than-anticipated margins on sales revenue from excess power.

Capital Commitments and Contractual Obligations
     The Vermont utility is a capital intensive operation, as it requires annual construction expenditures to maintain the distribution system. Our five-year capital expenditure plan is expected to range from $85 million to $95 million between 2004 and 2008.

     Our significant contractual obligations as of December 31, 2003 are summarized in the table below.

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Financing/Credit Ratings/Capitalization
Utility Total utility long-term debt maturities and sinking fund requirements at December 31, 2003, amounted to $75 million related to our Second Mortgage Bonds, which mature on August 1, 2004. We are considering alternative refinancing arrangements. Currently, we intend to and have the ability to refinance the $75 million at maturity. No payments are due on long-term debt for 2005 through 2007. Substantially all of the our utility property and plant is subject to liens under the First and Second Mortgage Bonds.

     We have $16.9 million of letters of credit expiring on November 30, 2004. These letters of credit support three series of Industrial Development/Pollution Control Bonds, totaling $16.3 million, and are secured by a first mortgage lien on the same collateral supporting our First Mortgage Bonds.

     At December 31, 2003, we were in compliance with all debt covenants related to our various debt agreements; these agreements contain financial and non-financial covenants.

Non-Utility  Catamount has a $25 million revolving credit/term loan facility and letters of credit, with $2.5 million outstanding at December 31, 2003. 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 two more years. Under the two-year extension, Catamount can borrow against new operating projects subject to terms and conditions of the facility. 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.  Catamount's long-term debt maturities, including its office building mortgage, total $2.7 million for 2004. Catamount's long-term debt contains financial and non-financial covenants. At December 31, 2003, Catamount was in compliance with all covenants under the credit facility.

     In January 2004, Catamount paid off the outstanding $2.5 million on the term loan and in February 2004 Catamount notified the lender of its intent to terminate the credit facility. The termination is effective 90 days after notification to the lender. Catamount is now soliciting proposals from selected financial institutions for corporate and/or development credit facilities that will meet its business needs. Catamount cannot predict whether it will be able to ultimately solicit and enter into an appropriately priced corporate and/or development credit facility. The office building mortgage matures on April 15, 2004 and Catamount expects to pay the outstanding balance in full.

Credit Ratings  On August 12, 2003, Standard & Poor's ("S&P") affirmed our corporate credit rating at 'BBB-', and reported the rating outlook as stable. S&P indicated that the affirmation was based upon an improving regulatory environment, a diverse customer mix, stable demand growth and low operating risk. S&P's stable outlook was based upon the Company's stable utility segment that should allow the Company to preserve its financial profile.

     On September 10, 2003, Fitch IBCA ("Fitch") upgraded our first mortgage bond rating to 'BBB+' from 'BBB' and second mortgage bond rating to 'BBB' from 'BBB-'. Fitch also affirmed our preferred stock rating at 'BB+'and reported the rating outlook as stable. Fitch indicated that the higher ratings reflect the Company's strengthening credit measures and lower business risk related to the 2001 rate order, which provided full recovery of Hydro-Quebec purchased power agreement costs. Another factor was the sale of Vermont Yankee, eliminating the Company's nuclear operating risk.

     Credit ratings should not be considered a recommendation to purchase stock. Current credit ratings are as follows:

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our financial statements are prepared in accordance with GAAP, requiring us to make estimates and judgments that affect reported amounts of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements. Our most critical accounting policies are described below.

Regulation  We prepare our financial statements in accordance with SFAS No. 71 for our regulated Vermont service territory and FERC-regulated wholesale business. We are regulated by the PSB, the NHPUC, the Connecticut Department of Public Utility and Control and the FERC, with respect to rates charged for service, accounting, financing and other matters pertaining to regulated operations. Under SFAS No. 71, we account for certain transactions in accordance with permitted regulatory treatment, as such, regulators may permit incurred costs, typically treated as expenses by unregulated entities, to be deferred and expensed in future periods when recovered in future revenues. In order for a company to report under SFAS No. 71, the company's rates must be designed to recover its costs of providing service and the company must be able to collect those rates from customers. If rate recovery of these costs becomes unlikely or uncertain, whether due to competition or regulatory action, this accounting s tandard would no longer apply to our regulated operations. Criteria that could give rise to the discontinuance of SFAS No. 71 include: 1) increasing competition that restricts the 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. We periodically review these criteria to ensure that the continuing application of SFAS No. 71 is appropriate. If we determine the Company no longer meets the criteria under SFAS No. 71, the accounting impact would be an extraordinary charge to operations of about $41.8 million on a pre-tax basis as of December 31, 2003, assuming no stranded cost recovery would be allowed through a rate mechanism. Based on a current evaluation of the factors and conditions expected to impact future cost recovery, we believe future recovery of our regulatory assets in the State of Vermont and State of New Hampshire for our retail and wholesale businesses is probable.

Discontinued Operations The assets and liabilities of Connecticut Valley are classified as held for sale in the Consolidated Balance Sheets in accordance with SFAS No. 144. In addition, as required by SFAS No. 144, the results of operations related to Connecticut Valley are reported as discontinued operations, and prior periods have been restated to conform to this presentation. For presentation purposes, certain of the Company's common corporate costs, which were previously allocated to Connecticut Valley, have been reallocated back to continuing operations to reflect the sale's impact on continuing operations. These common costs amounted to about $1.3 million in 2003, $1.4 million in 2002 and $1.2 million in 2001, on an after-tax basis. We began to present Connecticut Valley as discontinued operations in the second quarter of 2003 based on the NHPUC's approval of the sale of Connecticut Valley's plant assets and franchise to PSNH. Prior to the second quarter of 2003, Connecticut Valley was rep orted as a separate segment.

Unregulated Business Results of operations of our unregulated subsidiaries are included in the Other Income and Deductions section of the Consolidated Statements of Income. Catamount's policy is to expense all screening, feasibility and development expenditures associated with investments in new projects. Catamount's project costs incurred subsequent to obtaining financial viability are recognized as assets subject to depreciation or amortization. Project viability is obtained when it becomes probable that costs incurred will generate future economic benefits sufficient to recover these costs.

Catamount evaluates the carrying value of its investments on a quarterly basis or when events and circumstances warrant. The carrying value is considered impaired when the anticipated undiscounted cash flow is less than the carrying value of each investment. In that event, a loss is recognized based on the amount by which the carrying value exceeds the fair value of the investment. In 2003, Catamount determined that its investments in Rupert and Glenns Ferry were impaired by amounts that were not significant. Catamount recorded after-tax asset impairment charges of $2.1 million in 2002 and $9.8 million in 2001, related to certain of its investments. These asset impairments were based on bids received from third parties for sale of certain investments or the projects' financial condition. See Diversification below for additional information.

Revenues Electricity sales to customers are based on monthly meter readings. Estimated unbilled revenues are recorded at the end of each monthly accounting period. In order to determine unbilled revenues, the Company makes 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.

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Income Taxes In accordance with SFAS No. 109, Accounting for Income Taxes ("SFAS No. 109"), we recognize 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 if it is more likely than not such tax assets will be unrealized. In the third quarter of 2003, the Company reduced certain income tax valuation allowances at Catamount by about $2.3 million, reflecting Management's best estimate that deferred income taxes for certain previously recorded equity losses will be realized. See Income Tax Issues below for additional information.

Decommissioning Cost Estimates Accounting for decommissioning costs of nuclear power plants involves significant estimates related to decommissioning costs to be incurred many years in the future. Primary drivers of changes to these estimates include, but are not limited to, increases in projected costs of spent fuel storage, security and liability and property insurance. We own, through equity investments, 2 percent of Maine Yankee, 2 percent of Connecticut Yankee and 3.5 percent of Yankee Atomic. All three plants are completely shut down and are conducting decommissioning activities. We are responsible for paying our equity ownership percentage of decommissioning costs and all other costs for these plants.

As of December 31, 2003, based on the most recent estimates provided, our share of remaining costs to decommission these nuclear units is about $7.4 million for Maine Yankee, $13.3 million for Connecticut Yankee and $7.5 million for Yankee Atomic. These estimates are recorded in the accompanying Consolidated Balance Sheets as nuclear decommissioning liabilities (current and non-current) with a corresponding regulatory asset or other deferred charge. We will adjust associated regulatory assets, other deferred charges and nuclear decommissioning liabilities when revised estimates are provided.

Based on the current regulatory process, we believe our proportionate shares of Maine Yankee, Connecticut Yankee and Yankee Atomic decommissioning costs will be recovered through rates. See Power Supply Matters - Nuclear Generating Companies below for more information.

     We are also responsible for our 1.7303 joint-ownership percentage of Millstone Unit #3 decommissioning costs. Our contributions to the Millstone trust funds have been suspended based on the lead owner's representation to various regulatory bodies that the Trust Fund, for its share of the plant, exceeded the Nuclear Regulatory Commission's minimum calculation required. We could choose to renew funding at our discretion as long as the minimum requirement is met or exceeded. Currently, we are recovering these costs in rates. Prior to January 1, 2003, these amounts were applied to reduce certain regulatory assets. Since January 1, 2003, funds collected through retail rates are being recorded as a regulatory liability, to be addressed in our next rate proceeding.

Pension and Postretirement Benefits We record 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 a 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, 2003, the discount rate was decreased from 6.5 percent to 6 percent, in light of long-term interest rates remaining at historically low levels.

• Expected Return on Plan Assets ("ROA") - We project the future ROA based principally on historical returns by asset category and expectations for future returns, in part on simulated capital market performance over the next 10 years. The projected future value of assets reduces the benefit obligation a company will record. At September 30, 2002, the ROA changed from 8.5 percent to 8.25 percent. This rate was used to determine the annual expense for 2003 and the same rate will be used to determine the 2004 expense.

• Rate of Compensation Increase - We project employees' annual pay increases, which are used to project employees' pension benefits at retirement. As of September 30, 2003, the rate of compensation increase was changed from 4 percent to 3.75 percent based on lower than previously projected trends in cost-of-living increases.

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• Health Care Cost Trend - We project expected increases in the cost of health care. For measurement purposes, we assumed a 12 percent annual rate of increase in the per capita cost of covered health care benefits for pre-65 claims, and an 11.5 percent increase for post-65 claims, for fiscal 2004. These assumptions were based on expected higher health care costs.
  
• Amortization of Gains/(Losses) - We 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. We recognize these gains and losses ratably over a five-year period.

     The market value of pension plan trust assets was affected by sharp declines in the capital markets in 2001 and 2002, while favorable market returns in 2003, of about $12.1 million, helped to partially offset the market value decrease. Annual pension cost increased by $1.7 million for 2003 of which $1.4 million is reflected in results of operations and $0.3 million was allocated to accounts which are capitalized for accounting purposes.

     Pension costs and cash funding requirements are expected to increase in future years. As of December 31, 2003, the market value of pension plan trust assets was $61.3 million, including $42.5 million in marketable equity securities and $18.8 million in debt securities. Pension plan trust assets were $55.9 million at December 31, 2002, including $34.8 million in marketable equity securities and $21.1 million in debt securities.

     Postretirement costs also increased by $0.6 million for 2003 due to higher-than-expected medical claims experience. Of that amount, $0.4 million is reflected in results of operations and $0.2 million was allocated to accounts which are capitalized for accounting purposes.

     See Note 10 to the Consolidated Financial Statements for additional information related to Pension and Postretirement Benefits.

RESULTS OF OPERATIONS
     The following sections of Management's Discussion and Analysis compare the results of operations for each of the three years ended December 31, 2003, 2002 and 2001 and should be read in conjunction with the consolidated financial statements and accompanying notes included elsewhere in this report.

Consolidated Summary: Consolidated 2003 earnings were $19.8 million, or $1.57 per basic and $1.53 per diluted share of common stock. Consolidated 2002 earnings were $19.8 million, or $1.56 per basic and $1.53 per diluted share of common stock, while 2001 earnings were $2.4 million, or $.06 per basic and diluted share of common stock.

     Discontinued operations of Connecticut Valley for 2003 contributed $1.4 million, or $.12 per basic and diluted share of common stock. It contributed $1.5 million, or $.13 per basic and diluted share of common stock, in 2002 and $1.7 million, or $.14 per basic and diluted share of common stock, in 2001. Connecticut Valley's plant assets and franchise were sold to PSNH on January 1, 2004.

     The Vermont utility earnings were above the allowed rate of return on common equity of 11 percent for the 12 months ended December 31, 2003, resulting in a $1.5 million, after-tax, reduction of the Vermont utility's earnings, to stay below the mandated earnings cap. Similarly, in 2002 the Vermont utility earnings were reduced by about $0.4 million, after-tax. We recorded related pre-tax regulatory liabilities amounting to about $2.5 million in 2003 and $0.7 million in 2002, which are expected to be used to decrease deferred charges on the balance sheet at December 31, 2003.

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2003 vs. 2002:
     The following table provides a reconciliation of 2003 and 2002 diluted earnings per share:

     In summary, 2003 retail sales revenue increased $3.2 million over 2002, primarily due to increased retail mWh sales from colder winter months in the first quarter of 2003. Net power costs in 2003 increased about $3 million compared to 2002. Of that amount $2.2 million was related to state tax benefits realized by Vermont Yankee in 2002 as a result of the sale of the plant. These tax benefits were passed through to the plant owners, partly in the form of lower purchased power billings from Vermont Yankee, which reduced 2002 purchased power expense. We discuss operating revenues and net purchased power and production fuel costs in more detail below.

     Other factors affecting 2003 earnings compared to 2002 included lower transmissions costs, lower interest expense, internal cost cutting efforts, lower bad debt reserves in 2003 compared to 2002 due to several customer bankruptcies in 2002, and the favorable impact of an increase in the cash surrender value of certain life insurance policies due to financial market results. Offsetting these favorable items were increased employee-related costs, lower equity in earnings from Vermont Yankee due to the July 2002 sale of the plant, including Vermont Yankee's state tax benefits, and the Vermont utility mandated earnings cap described above. Earnings in 2002 also included a reversal of environmental reserves and a one-time transaction cost related to the sale of Vermont Yankee, with no comparable items in 2003.

     In the third quarter of 2003, the consolidated federal income tax provision reflected a benefit of about $2.3 million related to capital gain treatment on the proposed sale of Connecticut Valley (which closed January 1, 2004). The capital gain treatment allowed for a reduction of certain income tax valuation allowances at Catamount, reflecting Management's best estimate that deferred income taxes for certain previously recorded equity losses will be realized. See Income Tax Issues below.

     Excluding these income tax benefits, Catamount recorded losses of about $1.6 million in 2003, primarily related to lower equity earnings and lower project development revenue, offset by lower interest expense due to lower debt. This compares to earnings of about $1.5 million in 2002, primarily related to higher equity earnings from several of its investments and realized development revenue upon the sale of another investment, offset by asset impairment charges taken for its investments that were sold in the fourth quarter of 2002.

     Eversant recorded earnings of $0.5 million in 2003 compared to losses of $0.5 million in 2002, resulting from discontinuing its efforts to pursue unregulated business opportunities, partially offset by the reversal of an IRS interest expense accrual in 2002, previously recorded in the fourth quarter of 2001.

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2002 vs. 2001:
     The following table provides a reconciliation of 2002 and 2001 diluted earnings per share:

     In summary, 2002 retail sales revenue increased $7.7 million from higher average retail rates due to a 3.95 percent retail rate increase beginning July 1, 2001, and increased mWh sales. Net power costs increased $6.4 million related to a number of factors including lower resale sales revenue, increased purchases to support higher retail sales, and several one-time items in 2001 with no comparable items in 2002. We discuss operating revenues and net purchased power and production fuel costs in more detail below.

     Other factors affecting 2002 results compared to 2001 included higher other operating revenue related to the sale of non-firm transmission under our open access transmission tariff, offset by higher operating and other costs. In 2001, the Company wrote off $9 million, pre-tax, of certain regulatory assets related to its July 2001 rate case settlement. There was no such comparable item in 2002.

     Catamount's earnings were $1.5 million in 2002 versus losses of $8.7 million in 2001. Compared to 2001, its 2002 earnings reflected higher equity in earnings from several of its investments and realized development revenue upon the sale of one of its investments in the fourth quarter of 2002, offset by after-tax asset impairment charges of $2.1 million taken for its investments that were sold in the fourth quarter of 2002. In 2001, Catamount's after-tax asset impairment charges amounted to about $9.8 million related to several of its investments. See Diversification below for a more detailed discussion of Catamount's investments and these after-tax asset impairment charges. Eversant's net losses were $1.6 million lower in 2002, primarily related to a 2001 write down of its investment in the Home Service Store, Inc. ("HSS") to fair value. See Diversification below for a more detailed discussion of Eversant.

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CONSOLIDATED INCOME STATEMENT DISCUSSION
The following includes a more detailed discussion of the components of our Consolidated Income Statements and related year-over-year variances. This discussion follows the order of the Consolidated Income Statements.

Operating revenues: The majority of our operating revenues are generated through retail sales from our regulated Vermont utility business. Other resale sales are related to the sale of excess power from our owned and purchased power supply portfolio. These resale sales are also discussed in Net Purchased Power and Production Fuel Costs below. Operating revenues and related mWh sales for 2003, 2002 and 2001 are summarized below:

     Differences in Operating revenues were due to changes in the following:

2003 vs. 2002:

Operating revenues increased $11.6 million in 2003 as a result of the following factors:

• Retail sales increased $3.2 million primarily due to an 11,820 mWh increase in sales volume. These sales are affected by weather and economic conditions. In 2003, colder weather in the first quarter increased residential sales volume, while relatively weak economic conditions decreased sales volume for our Commercial and Industrial customers.
• Other resale sales increased $8.8 million due to higher rates for contract sales and wholesale market prices in ISO-New England, and more power available for resale in 2003. The reasons we had more mWh available for resale are described in more detail in Net Purchased Power and Production Fuel Costs below.
• Sales to Connecticut Valley under the RS-2 power contract decreased $0.5 million due to lower volume and lower unit costs under the contract.

Operating revenues increased $1.5 million in 2002 due to the following factors:

• Retail sales increased $7.7 million mostly from higher average retail rates due to a 3.95 percent retail rate increase beginning July 1, 2001, and a 1.2 percent increase in mWh sales.
• Entitlement sales decreased $7.3 million due to the October 2001 completion of a five-year power contract in which we sold 15 percent of our share of Vermont Yankee output at full cost.

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• Other resale sales decreased $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 reasons we had more mWh available for resale are described in more detail in Net Purchased Power and Production Fuel Costs below.
• Other revenues increased $1.4 million primarily due to the sale of non-firm transmission under our open-access transmission tariff.

Net Purchased Power and Production Fuel Costs: The cost components of net purchased power and production fuel for 2003, 2002 and 2001 are summarized below. These costs are shown net of entitlement and other resale sales revenue to reflect net power costs to support our load requirements. Other resale sales are related to sales of excess power from our owned and purchased power supply portfolio. The amount of related revenue is dependent on contract or ISO-New England market prices at the time of the sales. Also see Power Supply Matters below for a detailed discussion of our power supply sources, power management, purchased power commitments and nuclear investments.  

     As shown in the table above, purchased energy increased significantly in 2003 versus 2002 and 2001, while purchased capacity decreased significantly over the same periods. This shift in purchased power cost structure is related to the July 31, 2002 sale of Vermont Yankee. We continue to purchase a similar share of plant output, but all purchases made under the purchased power agreement ("PPA") are recorded as energy purchases. The majority of these purchases were recorded as capacity purchases when we owned the plant.

     In 2002, based on a PSB-approved accounting order, we deferred about $5.2 million of Vermont Yankee sale related costs including a portion of PPA costs that were higher than estimated costs had we continued to own and operate the plant for the full year. This brought our overall Vermont Yankee costs in line with those experienced in prior years.

Net purchased power and production fuel costs increased about $3 million in 2003 as a result of the following factors:

• A $10.6 million increase in purchased power costs primarily due to:

• An $11.6 million increase in Vermont Yankee related costs as a result of higher output from the plant in 2003 which increased purchases by about $8.2 million, and a $3.4 million net increase due to accounting for Vermont Yankee including the 2002 sale. The sale-related items included a $5.2 million deferral of energy costs as described above, and a $2.2 million reduction in 2002 power costs due to state tax benefits realized by Vermont Yankee that were passed on to the Vermont Yankee sponsors. These items were offset by a decrease of about $4 million due to the elimination of amortizations for Vermont Yankee nuclear refueling outages.
• A $2 million increase in ISO-New England capacity charges due to credits we received in 2002 for our share of revenues from the ISO-New England capacity deficiency pool. We did not receive these credits in 2003.
• A $1 million increase in purchases from independent power producers due to higher volume and rates.
• A $1.7 million decrease in purchases from Hydro-Quebec due to fewer deliveries.
• A $1.3 million decrease in short-term and spot energy purchases.
• A $1 million decrease in installed capacity purchases due to lower rate and volume.

• An $8.8 million increase in other resale sales related to more mWh available for resale in 2003, at higher contract rates and higher wholesale market prices in New England. The higher contract rates were related to a forward sale in 2003 in which we sold about 306,000 mWh for the period February through December 2003. In 2002 most of our resale sales were at ISO-New England market prices. We had more mWh available for resale primarily due to increased output from Vermont Yankee and Millstone, as each plant was off-line for scheduled refueling and maintenance in 2002. Also Vermont Yankee had a second quarter 2002 unscheduled outage for fuel rod repairs.

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• A $1.2 million increase in production fuel costs related to our joint-owned units. Wyman and McNeil generated more mWh in 2003 and at higher energy rates. Also, Millstone Unit #3 generated more mWh in 2003.

2002 vs. 2001:

Net purchased power and production fuel costs increased about $6.4 million in 2002 due to the following factors:

• Lower wholesale market prices in 2002 reduced revenue from resale sales by about $3.2 million. These resale sales offset the cost of power, so reduced revenue resulted in higher net power costs.
• Power requirements related to increased retail sales, losses, and capacity needs increased purchased power costs by about $1.1 million.
• Lower net Vermont Yankee costs of about $1.8 million related to the favorable impact of a $5.2 million deferral of energy costs as described above and the favorable impact of a $2.2 million reduction in purchased power expense due to state tax benefits realized by Vermont Yankee and passed through to the owners. Also, Vermont Yankee purchases increased by about $5.5 million in 2002 due to an 11.8 percent increase in our entitlement share of plant output beginning March 2002 based on negotiations with secondary purchasers. This also made available an additional 118,000 mWh.
• A $1.6 million decrease in ISO-New England capacity costs related to higher credits in 2002 for our share of the ISO-New England capacity deficiency pool.
• A $5.4 million unfavorable impact resulting from items in 2001 with no comparable items in 2002, including, 1) the June 2001 rate case settlement that ended 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 2) 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.

Operating Expenses:  Operating expenses represent costs incurred to support our core business. These expenses, excluding purchased power and production fuel costs, are described below.

Production and Transmission: These are expenses primarily associated with generating electricity from our wholly and jointly owned units and transmission of electricity. Fuel-related costs are discussed in Net Purchased Power and Production Fuel Costs above. There was no significant variance in these expenses for 2003 versus 2002 or for 2002 versus 2001.

Other operation  This is primarily related to operating activity such as customer accounting, customer service, administrative and general and other operating costs incurred to support our core business. These costs amounted to about $46.7 million in 2003, $43.5 million in 2002 and $42.8 million in 2001. The $3.2 million increase for 2003 versus 2002 and $0.7 million increase for 2002 versus 2001 are primarily related to the Vermont utility's mandated earnings cap, which resulted in a pre-tax expense of $2.5 million in 2003 and $0.7 million in 2002 to stay below the mandated earnings cap. We also recorded related pre-tax regulatory liabilities of about $2.5 million in 2003 and $0.7 million in 2002, which is expected to be used to decrease deferred debits on the balance sheet at December 31, 2003.

     Other factors affecting 2003 versus 2002 included a $1.7 million reversal of environmental reserves in 2002, which results in an unfavorable variance when comparing 2003 versus 2002, and higher employee-related costs, offset by internal cost cutting efforts, and lower bad debt reserve adjustments in 2003 compared to 2002 due to several customer bankruptcies in 2002.

Maintenance This is primarily related to costs associated with maintaining our electric distribution system. There was no significant variance in these expenses for 2003 versus 2002 or 2002 versus 2001.

Depreciation We use the straight-line remaining-life method of depreciation. There was no significant variance for 2003 versus 2002 or for 2002 versus 2001.

Other taxes, principally property taxes This is primarily related to property taxes and payroll taxes. There was no significant variance in these expenses for 2003 versus 2002 or for 2002 versus 2001.

Taxes on Income Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences and changes in valuation allowances for the periods. See Income Tax Issues below.

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Equity in earnings of affiliates:  These are related to our investments in VELCO and Vermont Yankee. Equity in earnings of affiliates amounted to about $1.8 million in 2003, $3.9 million in 2002 and $2.7 million in 2001. The $2.1 million decrease for 2003 versus 2002 and $1.2 million increase for 2002 versus 2001 were primarily related to state tax benefits realized by Vermont Yankee in 2002 as a result of the sale of the plant. These tax benefits were passed through to the plant owners, partly in the form of higher equity in earnings, with the remaining through lower purchased power expense as described above. Additionally, the July 2002 sale of the Vermont Yankee plant has reduced our ongoing equity in earnings from that investment. See Power Contract Commitments - Vermont Yankee below for more detail.

Other income, net: These income items, net of deductions, are related to the non-operating activities of the utility business and the operating activities of our unregulated businesses. Other income, net amounted to about $2.7 million in 2003 and $1.6 million in 2002. In 2001 Other income, net amounted to a deduction of about $16.3 million. The year-over-year variances were as follows (dollars in millions):

     UtilityBusiness  In 2003, the cash surrender value of certain life insurance policies increased significantly due to financial market results. This lowered life insurance expense in 2003. In 2002, we made a one-time payment of $1 million to the non-Vermont owners related to closing the Vermont Yankee sale. Also in 2001, we had to write off $9 million of certain regulatory assets as a result of our June 26, 2001 rate case settlement with the PSB.

     Unregulated Businesses   In 2003, Catamount net revenues and expenses decreased $7.3 million due to lower equity earnings from several of its investments and realized development revenue in 2002 upon the sale of one of its investments. Catamount also had pre-tax asset impairment charges of $2.8 million in 2002 and $8.9 million in 2001.

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Discontinued Operations:   This represents results of operations related to Connecticut Valley, which is classified as held for sale. See discussion of Discontinued Operations above.

Dividends on preferred stock:  Preferred stock dividends decreased by $0.3 million in 2003 and $0.2 million in 2002 due to lower outstanding preferred stock balances.

POWER SUPPLY MATTERS

Sources of Energy We purchase about 90 percent of our power under several contracts of varying duration. The remaining is supplied by our jointly and wholly owned generating facilities, and short-term purchases. Our power supply portfolio includes a mix of base load and schedulable resources to help cover peak load periods. A breakdown of energy sources is shown below:

     Our 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. Our wholly owned units include 20 hydroelectric generating units, two oil-fired gas turbines and one diesel peaking unit with a combined nameplate capability of 73.6 MW.  

     We have a long-term power contract with Hydro-Quebec and a long-term power contract for purchase of about 35 percent of Vermont Yankee plant output. These contracts support about 90 percent of our total annual energy (mWh) purchases. We are required to purchase power from various Independent Power Producers ("IPPs") under long-term contracts. These contracts are discussed in more detail below.

Power Supply Management We engage in short-term purchases and sales in the wholesale markets administered by the New England Independent System Operator ("ISO-New England") and with other third parties, primarily in New England, to minimize net power costs and risks to our customers. Based on commitments and contracts, we expect that net purchased power and production fuel costs will average approximately $125 million to $136 million per year for the years 2004 through 2008. Our long-term power forecast reflects energy amounts excess to that required to meet load requirements; therefore net power costs are dependent, in part, upon wholesale power market prices. Additionally, the January 1, 2004, sale of Connecticut Valley's assets and termination of its power contract released an average of about 11 MW on-peak and 17 MW off-peak of our power supply mix for future disposition.

     On an hourly basis, power is sold or bought through ISO-New England to balance our resource output and load requirements. From time to time, we enter into forward sale transactions in order to reduce volatility of our forecasted power costs. We may also enter into forward purchase transactions, when our forecasts reflect deficiencies such as scheduled refueling outages at Vermont Yankee. For the period February through December 2003, we sold about 306,000 mWh to a third party under a forward sale contract. In December 2003, we entered into a forward sale contract for about 148,400 mWh for the period January through March 2004, and a forward purchase contract for about 27,100 mWh for April 2004 in anticipation of a Vermont Yankee scheduled refueling outage. These forward transactions are in addition to our hourly purchases and sales with ISO-New England; however they decrease the volume of those hourly transactions.

     We also continue to monitor, and adapt to, changes to New England wholesale power markets and open access transmission systems. Related to the wholesale power markets, in March 2003, ISO-New England implemented Standard Market Design ("SMD"), a significant step to restructuring the wholesale energy markets in the Northeast. The move to regional transmission organizations ("RTO") also continues. SMD has impacted wholesale power prices related to short-term sales and purchases as well as the costs of our own generation. Although we expect that the RTO will impact our transmission costs at some point, we are not able to predict the nature of that impact. Below is a brief discussion of SMD and RTO.

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Standard Market Design
     On March 1, 2003, ISO-New England moved to a new market structure referred to as SMD. Some of the market changes include:

• Energy pricing now includes the costs (or benefits) of transmission congestion and marginal losses experienced at each location within the region. This is known as locational marginal pricing. Previously, costs of congestion and average losses were spread across New England energy providers on a pro rata basis.

• Location-specific pricing, based on where Generators and load connect to the New England system. Generation is priced at specific location 'nodes' while load is priced by 'zones' (each state is a zone, except Massachusetts, which is comprised of three zones).
• Day-ahead and real-time energy markets, allowing participants to settle transactions involving load and generation in real-time or one day in advance.
• An auction-based system of Financial Transmission Rights ("FTR") allowing participants to hedge congestion risks. FTR holders are paid (or charged) the day-ahead congestion value of the transmission path for which they hold an FTR, while auction proceeds are distributed via Auction Revenue Rights to load entities that experience day-ahead congestion or companies that increase the capacity of the network.

• Increased ISO-New England financial assurance requirements for market participants, based on their credit ratings and financial conditions.

     In general, we own or hold entitlements to generation that can be self-scheduled in the day-ahead or real-time market. We have been using the day-ahead market to clear the majority of our load and generation, including generation resources that we self-schedule, with any remaining resources and residual load settling in the real-time market.

     At this time, much of the cost of New England's existing and new high-voltage transmission system (115 kV looped facilities) is shared by all New England utilities. VELCO is planning several significant upgrades, which have been approved by the New England Power Pool for shared cost treatment. Vermont has traditionally been a significantly higher than average transmission cost jurisdiction. The new approach is advantageous to the Company's cost and reliability in providing service to its customers because our load share is a small fraction of total New England load, and the facilities VELCO is planning improve both the reliability and efficiency (i.e., losses and congestion) of the transmission network. We will pay a share of such projects elsewhere in New England but the net economic effect is expected to be beneficial, and better reliability elsewhere in the region benefits Vermont's reliability because of the highly integrated nature of New England's high voltage network. However, the cost of other future transmission facilities that do not qualify for cost sharing will be charged only to the requesting entity and our share of such costs will be affected by FERC approved cost-allocation rulings contained in VELCO's and the Company's tariffs and agreements.

Regional Transmission Organizations ("RTO")
     We operate our transmission system under an open-access tariff, pursuant to FERC Order No. 888. In 1999, FERC began work to amend regulations and facilitate formation of RTOs, and in 2001, FERC issued Order No. 2000 for that purpose. Since that time, we have participated in numerous related proceedings, including discussions to create an Open Access Transmission Tariff and Transmission Owners Agreement to govern the provision of transmission services.

     In July 2002, FERC issued a Standard Market Design Notice of Proposed Rulemaking to establish nationwide rules for power markets and RTOs. The rulemaking was designed to separate governance and operation of the transmission system from generation companies and other market participants and facilitate power markets with common rules.

     On October 31, 2003, ISO-New England and the transmission-owning entities in New England, including the Company, filed a joint proposal with FERC to create an RTO for New England. Certain transmission owners in New England also reached an agreement to submit (no later than February 1, 2004) a tariff, agreements and other documents to FERC to include costs associated with certain transmission facilities, commonly referred to as the Highgate Facilities, in region-wide rates as set forth in the proposal to create an RTO for New England. We have agreed to defer the FERC filing to allow time for the RTO stakeholders' review process and expect to file shortly after this process is concluded. We cannot predict the outcome of this matter or its impact to the Company.

Power Contract Commitments
Hydro-Quebec We are 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.

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These related contracts altered the terms and conditions of 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, must "step-up" to the defaulting party's share on a pro rata basis. As of December 31, 2003, our obligation is approximately 46 percent of the total VJO Power Contract through 2016, which translates to about $734 million, on a nominal basis, over the contract term. The average annual capacity that we will purchase from January 1, 2004 through October 31, 2012 is 144.2 MW, with lesser amounts purchased thereafter through October 31, 2016. See Note 13 to the Consolidated Financial Statements for further discussion of this contract.

     In 2003, we purchased about $57.5 million of energy and related capacity under the existing contracts with Hydro-Quebec. Estimated purchases under these contracts based on a load factor of 65 percent for 2004 and 2005, and 75 percent for 2006 through 2008, are expected to be about $58.2 million in 2004, $61.4 million in 2005, $62.1 million in 2006, $62.5 million in 2007 and $63.3 million in 2008.

     On January 30, 2004, Hydro-Quebec notified the VJO that it is not likely that Hydro-Quebec will reschedule deliveries of energy not delivered during the prior contract year (November 1, 2002 through October 31, 2003) due to interconnection deficiencies. At this time, we are working with Hydro-Quebec to minimize such interconnection deficiencies through various scheduling modifications and use of interconnection facilities. We are unable to predict how this might impact our 2004 net power costs; however, under the VJO contract, we are responsible for paying capacity costs, and any reduced deliveries would either result in purchases of energy through short-term purchases, or decreased resale sales.

Vermont Yankee We have a 35 percent entitlement in Vermont Yankee plant output sold by Entergy to Vermont Yankee, through a long-term power purchase contract with Vermont Yankee, and one remaining secondary purchaser continues to receive a small percentage of our entitlement, reducing our entitlement to about 34.83 percent. The long-term contracts between Vermont Yankee and the entitlement holders and between Vermont Yankee and Entergy became effective on July 31, 2002, the same day that the Vermont Yankee nuclear plant was sold to Entergy. We no longer bear the operating costs and risks associated with running the plant or the costs and risks associated with the eventual decommissioning of the plant. We are responsible for the purchase of replacement power to serve our load requirements when the plant is not operating due to scheduled or unscheduled outages.

     The PPA through which Vermont Yankee purchases power from Entergy and in turn sells to its sponsors includes prices that generally range from 3.9 cents to 4.5 cents per kilowatt-hour through 2012. Effective November 2005, the contract prices are subject to a "low-market adjuster" that protects the Company and our power consumers if power market prices drop significantly. The low-market adjuster is a mechanism in which the PPA base contract price for each billing month is compared to a twelve-month average (ending in same billing month) of hourly market prices as defined in the PPA. If the twelve-month average market price is less than 95 percent of the base PPA contract price, then 105 percent of the twelve-month average market price will be used for the billing month. The low-market adjuster cannot exceed the base PPA contract price. If the market prices rise, however, contract prices are not adjusted upward. In addition to PPA charges, Vermont Yankee's billings to the sp onsors include certain of its residual costs of service through a FERC tariff to the Vermont Yankee sponsors. The PPA is expected to result in decreased costs over the life of the PPA when compared to the projected cost of continued ownership of the plant.

     In 2003, our Vermont Yankee purchases were about $65.2 million based on our entitlement share of plant output. Future purchases are expected to be $62.8 million in 2004, $57.7 million in 2005, $60.7 million in 2006, $57.9 million in 2007 and $59.2 million in 2008.

     In 2003, Entergy sought PSB approval to increase generation at the Vermont Yankee plant by 110 megawatts. On November 5, 2003, the DPS announced that it had agreed to support Entergy's proposed uprate including Entergy's agreement to provide outage protection indemnification for the Company and Green Mountain Power in case the uprate causes temporary outages that require the Vermont utilities to buy higher-cost replacement power. The outage protection coverage will be in place for three years, during which there may be uprate-related outages. We have indemnification rights up to about $2.8 million. The agreement requires PSB approval, and hearings began in January 2004.

     On February 10, 2004, Entergy notified us that it expects that the plant output will be reduced beginning after the April 2004 scheduled refueling outage, and continuing until Entergy receives Nuclear Regulatory Commission approval for the uprate, which is expected no earlier than November 2004. This will reduce our 182 MW entitlement by about 7 MW during this period. We cannot predict the outcome of this matter or how it might affect

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future operations of Vermont Yankee; but a decrease in the output of Vermont Yankee could have a material impact on us, given that our long-term contract for Vermont Yankee output provides a significant part of our power supply mix.

Independent Power Producers ("IPPs") We purchase 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 ("VEPPI") that purchases and redistributes the power to all Vermont utilities. In 2003, we received 164,918 mWh under these long-term contracts, including 142,968 mWh received through VEPPI. These IPP purchases account for 6.2 percent of our total mWh purchased and 11 percent of purchased power costs. Estimated purchases from IPPs are expected to be $18.8 million in 2004, $18.8 million in 2005, $18.5 million in 2006, $19.2 million in 2007 and $19.8 million in 2008. These amounts reflect annual savings credits of about $0.6 million related to the IPP settlement that is described in Note 13 to the Consolidated Financial Statements.

Wholly Owned Generating Units We own and operate 20 hydroelectric generating units, two oil-fired gas turbines and one diesel peaking unit with a combined nameplate capability of 73.6 MW.

     We are in the process of relicensing or preparing to license six separate hydroelectric projects under the Federal Power Act. These projects, some of which are grouped together under a single license, represent about 24.5 MW, or 54.8 percent, of our total hydroelectric nameplate capacity. The FERC is expected to impose conditions designed to address impacts on fish and the environment. We cannot predict the specific impact of any conditions, but capital expenditures and operating costs are expected to increase in the short term and net generation from these projects will likely decrease.

     Peterson Dam We have 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 about 3,000 homes per year. In April 2002, the parties, including the Town of Milton and the DPS, entered into a Conceptual Agreement that outlined a negotiated settlement on relicensing, including the removal of Peterson Dam.
    
     In January 2003, the Company, the Vermont Agency of Natural Resources ("Agency"), VNRC and other parties reached an agreement to allow us to relicense the four dams we own and operate on the Lamoille River. According to the agreement, we will receive a water quality certificate from the State, which is needed for FERC to relicense the facilities for 30 years. The agreement also stipulates that subject to various conditions, we must begin decommissioning Peterson Dam in about 20 years. The agreement 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. On July 31, 2003, the Agency published its draft water quality certificate and on October 29, 2003, pursuant to the schedule set forth in the agreement, we filed a petition with the PSB for approval of the rate recovery mechanisms. We anticipate the PSB will establish a schedule for additional testimony, di scovery and an order in 2004. We cannot predict the outcome of this matter. 

Nuclear Generating Companies We are one of several sponsor companies with ownership interests in Maine Yankee, Connecticut Yankee and Yankee Atomic. We are responsible for paying our ownership percentage of decommissioning costs and all other costs for each plant. These companies have permanently shut down generating activities and are conducting decommissioning activities. We also have a 1.7303 percent joint-ownership interest in Millstone Unit #3. Our obligations related to the eventual decommissioning of the Vermont Yankee plant ceased when the plant was sold to Entergy on July 31, 2002.

Millstone Unit #3 We have an external trust dedicated to funding our joint ownership share of future decommissioning for Millstone Unit # 3. As a joint owner, we are responsible for our share of nuclear decommissioning costs. Contributions to the Millstone Unit #3 Trust Fund have been suspended based on the lead owner's representation to various regulatory bodies that the Trust Fund, for its share of the plant, exceeded the Nuclear Regulatory Commission's minimum calculation required. We could choose to renew funding at our own discretion as long as the minimum requirement is met or exceeded.

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Maine Yankee, Connecticut Yankee and Yankee Atomic  Our share of estimated future payments related to the decommissioning of Maine Yankee, Connecticut Yankee and Yankee Atomic, based on current forecasts for each plant, are as follows (dollars in millions):

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     On August 22, 2003, Connecticut Yankee formally denied the allegations of Bechtel's amended complaint and filed a counterclaim. It alleges various material breaches of contract that justified Bechtel's termination, along with misrepresentation and bad faith. It also requests that Bechtel be found responsible for project costs in excess of Bechtel's unpaid contract balance, and for other damages. The lawsuit has been assigned to the Complex Litigation Docket and has been set for a jury trial beginning May 4, 2006. Connecticut Yankee also notified Bechtel's surety of its intention to file a claim under the performance bond.

     At Connecticut Yankees' December 2003 Board of Directors meeting, the Board endorsed an updated estimate of the costs for the plant's decommissioning project. This updated cost estimate referred to as the "2003 Estimate" of approximately $823 million, covers the time period 2000 through 2023 and represents an aggregate increase of approximately $413 million in nominal dollars over the cost estimate in its 2000 FERC rate case settlement, which covered the same time period. It also includes increased costs from a November 2002 updated estimate which were related to projected costs of spent fuel storage, security, and liability and property insurance. The 2003 Estimate represents an increase of about $389 million in 2003 dollars. Prior to the approval of the cost estimate in the 2000 FERC settlement, Connecticut Yankee had also incurred about $184 million for decommissioning costs in the 1997 - 1999 timeframe.

     The 2003 Estimate is still undergoing review; it reflects the fact that Connecticut Yankee is now directly managing the work (self performing) to complete decommissioning of the plant following the default termination of Bechtel as described above. Connecticut Yankee intends to update the estimate based on additional information when available including the results of competitive bidding of project work such as demolition. The 2003 Estimate does not include any allowance for relief of the Bechtel contract dispute or the DOE damage claim described above.

     Connecticut Yankee is also beginning the preparation of a rate case application that is required to be filed with FERC by July 1, 2004 under the terms of its 2000 FERC rate case settlement. While Connecticut Yankee has not determined the relief it will seek in the forthcoming application, it anticipates that annual decommissioning collections would have to be increased significantly, beginning January 2005, to support anticipated project cash flow over the next several years and to fund long-term fuel storage through 2023.

     Our estimated aggregate obligation related to Connecticut Yankee is about $13.3 million. The timing, amount and outcome of these filings cannot be predicted at this time. We believe our share of Connecticut Yankee's decommissioning costs are probable of recovery in future rate proceedings.

Yankee Atomic: We have a 3.5 percent ownership interest in Yankee Atomic. Billings from Yankee Atomic ended in July 2000 based on their determination that they had collected sufficient funds to complete the decommissioning effort. We are not currently collecting Yankee Atomic costs in retail rates.

     In late 2002, Yankee Atomic revised its cost estimate for decommissioning the plant, reflecting an increase of about $190 million over prior estimates utilized by FERC. The increase was attributable to increases in projected costs of spent fuel storage, security, and liability and property insurance. In April 2003, Yankee Atomic filed with FERC for new rates to collect these costs from sponsor companies. FERC approved the resumption of billings starting June 2003 for a recovery period through 2010, subject to refund. The Company expects its share of these costs will be recoverable in future rates. In 2003, our share of Yankee Atomic's billings amounted to about $1.1 million. Based on a PSB-approved accounting order, we are deferring these costs.

DIVERSIFICATION
     Catamount Resources Corporation was formed to hold our subsidiaries that invest in unregulated businesses including Catamount and Eversant.

Catamount  As of December 31, 2003, Catamount has interests in nine operating independent power projects located in Rumford, Maine; East Ryegate, Vermont; Hopewell, Virginia; Rupert and Glenns Ferry, Idaho; Nolan County, Texas; Thetford, England; Thuringen, Germany and Mecklenburg-Vorpommern, Germany.

     Catamount is primarily focused on developing, owning and operating wind energy projects and is currently pursuing the sale of certain of its interests in non-wind electric generating assets. Depending on prices, capital and other requirements, Catamount will also entertain offers for the purchase of any of its remaining non-wind electric generating assets. Proceeds from the sales will be reinvested in the development of new wind projects and the acquisition of existing wind projects. Additionally, Catamount is seeking investors and partners to co-invest with

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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 strategy will be successful.

     Catamount has projects under development in the United States and United Kingdom. In February 2002, Catamount entered into a joint development agreement with force9energy Ltd. of England to develop wind projects in England, Scotland and Wales. In September 2002, Catamount established Catamount Energy Ltd., an English corporation, to hold Catamount's interests in England, Scotland and Wales "greenfield" development projects or projects that would be purchased by Catamount in early to mid-stage development. In July 2003, Catamount established Catamount Cymru Cyf., an English and Wales private limited company to develop a project located in Wales.

     In January 2004, Catamount Energy Limited and Catamount Cymru Cyf. issued stock to a third party Norwegian investor thereby diluting Catamount's interest to 50 percent.

     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 2003, Catamount ceased "greenfield" development in Germany to focus development efforts in the United States and United Kingdom.

Catamount Results
     In the third quarter of 2003, the consolidated federal income tax provision reflected a benefit of approximately $2.3 million. Capital gain treatment on the proposed sale of Connecticut Valley (which closed January 1, 2004) allowed for a reduction of certain income tax valuation allowances at Catamount (Fibrothetford Limited $1.7 million, Glenns Ferry and Rupert $0.6 million), reflecting Management's best estimate that deferred income taxes for certain previously recorded equity losses will be realized.

     Excluding these income tax benefits, Catamount recorded losses of about $1.6 million in 2003, primarily due to lower equity earnings and lower project development revenue, offset by lower interest expense due to lower debt. This compares to earnings of $1.5 million in 2002 and losses of $8.7 million in 2001. Its 2002 earnings compared to 2001 reflect higher equity in earnings from several of its investments and realized development revenue upon the sale of one of its investments in the fourth quarter of 2002, offset by after-tax asset impairment charges of $2.1 million taken for its investments that were sold in the fourth quarter of 2002. Also in 2001, Catamount had after-tax asset impairment charges of about $9.8 million related to several of its investments. Information regarding certain of Catamount's investments follows.

Glenns Ferry and Rupert Catamount is negotiating with a third party for the sale of its investment interests in Rupert and Glenns Ferry. Catamount cannot predict whether a sale will ultimately be consummated. Previously, in the fourth quarter 2001, Catamount recorded after-tax impairment charges of $3 million for all of its interests in the Rupert and Glenns Ferry projects due to the deteriorating financial condition of the projects' steam hosts essential to the projects' Qualifying Facility status and long-term viability.

     In May 2002, Rupert and Glenns Ferry were issued an Events of Default notice by their lender. Steam host restructurings in 2002 cured most of the events of default. Rupert cured its remaining events of default in March 2003 and management anticipates that Glenns Ferry will cure its remaining events of default by the end of 2004. Management does not believe this will have a material impact on Catamount.

Sweetwater 1 On June 30, 2003, Catamount entered into an equity commitment for up to a $10.1 million equity investment in the 37.5-MW wind farm in Nolan County, Texas known as Sweetwater 1. The project's financial advisor located an additional equity investor for the project, reducing Catamount's equity commitment. In December 2003, Catamount acquired its equity interest in Sweetwater 1 for $6.2 million.

Fibrothetford Limited Catamount had a Sale and Purchase Agreement with a third party for the sale of its Fibrothetford investment interests. In July 2003, the buyer suspended the sale and in December 2003, Catamount terminated the Sale and Purchase Agreement. The buyer is still interested in acquiring Catamount's investment interests, but Catamount cannot predict whether a sale will ultimately be consummated.

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     To the extent required, continuing equity losses are applied as a reduction to Catamount's note receivable balance from Fibrothetford. In 2003, Catamount reserved approximately $2 million against interest income on the note receivable. Previously, in the fourth quarter of 2001, Catamount recorded an after-tax impairment charge of $3.2 million and a valuation allowance for the $2.2 million deferred tax asset. The impairment charge was based on the expected market value of Catamount's interest given the project's financial condition at the time.

Heartlands Power Limited and Gauley River  In the fourth quarter of 2002 Catamount sold its interest in Heartlands Power Limited and Gauley River. The proceeds from the sales approximated the net book value of its investments in both projects. Also, in the third quarter of 2002, Catamount recorded after-tax impairment charges of $1.3 million related to Heartlands and $0.8 million related to Gauley River. At the time, the 2002 impairment charges were related to the pending sale of Heartlands, and funding requirements as a condition of the Gauley River Purchase and Sale Agreement. In 2001, Catamount recorded an after-tax impairment charge of $1.4 million related to Gauley River based on bids received from third parties, less estimated costs to sell.

Eversant As of December 31, 2003, Eversant had a $1.4 million equity investment, representing a 12 percent ownership interest in HSS, which has established a network of affiliate contractors who perform home maintenance repair and improvements for HSS members. Eversant accounts for this investment on a cost basis. In the third quarter of 2001, Eversant recorded a $1.2 million after-tax write-down of its investment in HSS to fair value based on an updated valuation at the time.

     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 AgEnergy's claim that Westfalia-Surge had not conducted itself in accordance with the exclusive distributorship agreement between the parties. On January 28, 2002, AgEnergy received an adverse decision related to the arbitration.  On November 6, 2002, Westfalia filed a Petition to Confirm the Arbitrator's Award, which effectively sought to expand the Arbitrator's Award. AgEnergy sought dismissal of the Petition to the extent it sought costs in excess of those established by the Arbitrator. The Petition was dismissed for lack of jurisdiction.

     Eversant's wholly owned subsidiary, SmartEnergy Water Heating Services, Inc. ("SEWHS"), engages in the sale or rental of electric water heaters in Vermont and New Hampshire. SEWHS had earnings of $0.5 million in 2003, $0.3 million in 2002 and $0.4 million in 2001.

     Overall, Eversant's 2003 earnings were $0.5 million, versus net losses of $0.5 million in 2002 and $2.1 million in 2001. In early 2002, we discontinued Eversant's efforts to pursue unregulated business opportunities except for SEWHS.

INCOME TAX ISSUES
     We account for income taxes in accordance with SFAS No. 109 which requires recognition of deferred tax assets and liabilities for the future tax effects of temporary differences between carrying amounts and the tax basis of assets and liabilities. Under this method, deferred income taxes result from applying the statutory rates to the differences between the book and tax basis of asset and liabilities.

Valuation Allowances  SFAS No. 109 prohibits the recognition of all or a portion of deferred income tax benefits if it is more likely than not that the deferred tax asset will not be realized. From January 1, 2003 to December 31, 2003, the valuation allowance decreased by about $3.4 million. All other deferred income taxes are expected to be realized. The $3.4 million decrease is related to the following:

• In the third quarter of 2003, Management determined that the Connecticut Valley sale agreement was more likely than not to occur, which afforded the Company the opportunity to realize capital gains on the sale. The capital gains treatment allowed for a $2.3 million reduction of certain tax valuation allowances at Catamount. These tax valuation allowances were primarily related to previously recorded equity losses resulting from fourth quarter 2001 asset impairments charges taken at Catamount for certain of its investments. At that time, the Company had determined that it was more likely than not that current or future income tax benefits would not be realized for these asset impairment charges, and it was Management's best estimate that it would not realize enough capital gains to offset the potential capital losses resulting from the asset impairment charges.

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• In the third quarter of 2003, the Company reduced the valuation allowance and corresponding deferred tax asset by about $1.9 million due to the reclassification of an equity method of accounting adjustment related to the financial statements from one of Catamounts foreign projects. This reclassification did not impact 2003 earnings.
• During 2003 additional valuation allowances of about $0.8 million were established for certain foreign losses related to Catamount's foreign investments. Management determined that it is more likely than not that a current or future income tax benefit would not be realized.

RECENT ACCOUNTING PRONOUNCEMENTS

     See Note 1 to the accompanying Consolidated Financial Statements.

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

Regulatory Risk Electric utility rates in Vermont are based on a utility's costs of service. As such, we are subject to Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation ("SFAS No. 71") which allows regulated entities, in appropriate circumstances, to establish regulatory assets and liabilities, and thereby defer the income statement impact of certain costs and revenues that are expected to be realized in future rates. If we determine the Company no longer meets the criteria under SFAS No. 71, the accounting impact would be an extraordinary charge to operations of about $41.8 million pre-tax basis as of December 31, 2003, assuming no stranded cost recovery would be allowed through a rate mechanism.

If retail competition is implemented in our Vermont service territory, we are unable to predict the impact on our revenues, our ability to retain existing customers and attract new customers or the margins that will be realized on retail sales of electricity, if any such sales are sought.

Interest Rate Risk As of December 31, 2003, we have $16.3 million of Industrial Development/Pollution Control bonds outstanding ($10.8 million with an interest rate that floats monthly based on short-term credit markets and $5.5 million that floats every five years based on comparable credit markets. All other utility debt has a fixed rate. There are no interest lock or swap agreements in place. Consolidated temporary cash investments amounted to $55.2 million at December 31, 2003, including $12.4 million related to the non-utility business. Interest rate changes could also affect estimates of pension and other benefit liabilities and expenses that could potentially require contributions to the pension trusts.

Equity Market Risk As of December 31, 2003, the pension trust and Millstone Unit #3 decommissioning trust held marketable equity securities of $42.5 million and $3.2 million, respectively. We also maintain a variety of insurance policies in a Rabbi Trust with a current value of $5.2 million. The current values of certain policies are affected by changes in the equity market.

Credit Risk We have $16.9 million of letters of credit expiring on November 30, 2004, secured by a first mortgage lien on the same collateral supporting our First Mortgage Bonds.  At December 31, 2003, the utility long-term debt maturities and sinking fund requirements is $75 million related to our Second Mortgage Bonds that mature on August 1, 2004. We are considering alternative refinancing arrangements and currently, we intend to and have the ability to refinance the $75 million at maturity. No payments are due on long-term debt for 2005 through 2007.

The Second Mortgage Bonds covenants contain limiting restrictions if those bonds receive a debt rating below BBB- from rating agencies. The current ratings of the bonds are BBB- (stable) from Standard & Poor's and BBB (stable) from Fitch. The limiting characteristics include, but are not limited to, certain restrictions on investments in unregulated subsidiaries, the incurrence of indebtedness and the payment of dividends. These restrictions are dependent on meeting both a Fixed Charge Coverage and a Cumulative Cash Flow test. We are currently in compliance with both calculations.

Unregulated Business - Catamount
Credit Risk  In December 2002, Catamount extended its corporate credit facility to November 2004. In February 2004, Catamount notified the lender of its intent to terminate the credit facility (the termination is effective 90 days after such notification.) Catamount is currently soliciting proposals from selected financial institutions for corporate and/or development credit facilities to meet its business needs. Catamount cannot predict whether it will be able to ultimately solicit and enter into an appropriately priced corporate and/or development credit facility.

Also see Item 7, Risk Factors for a more detailed discussion of business risks.

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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 sheets of Central Vermont Public Service Corporation and subsidiaries (the Company) as of December 31, 2003 and 2002, and the related consolidated statements of income, comprehensive income, changes in common stock equity and cash flows for each of the three years in the period ended December 31, 2003. 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 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 audits provide a reasonable basis for our opinion.

     In our opinion, the consolidated 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, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.

     As discussed in Note 4 to the consolidated financial statements, Connecticut Valley Electric Company, a wholly owned subsidiary of the Company, completed the sale of substantially all of its plant assets and its franchise to Public Service Company of New Hampshire on January 1, 2004.

Deloitte & Touche, LLP

Boston, Massachusetts

February 20, 2004

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

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