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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, Corporate Governance Guidelines, and Charters of the Audit, Compensation and Corporate Governance Committees, 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 e xecutive 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. Also see Part II Item 8, Note 14 for financial information regarding the Company's business segments.

The Company is the largest electric utility in Vermont and serves about 149,000 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. In 2004, the Company's sales to residential, commercial and industrial customers accounted for 80 percent of total mWh sales, and resale firm sales accounted for less than 1 percent. During the same period, the Company's other resale sales, which include contract sales, sales to ISO-New England and short-term system capacity sales, accounted for about 20 percent of total mWh sales. See Part II Item 7, Results of Operations for detailed information regarding the Company's Operating Revenues for the years ended December 31, 2004, 2003 and 2002. Sales to the five largest retail customers receiving electric service from the Company during 2004 accounted for about 6 percent of the Company's total electric revenues for the year. This compares to 5 percent during 2003 and 6 percent during 2002.

The Company's wholly owned subsidiary, Connecticut Valley Electric Company Inc. ("Connecticut Valley"), incorporated under the laws of New Hampshire on December 9, 1948, distributed and sold electricity in parts of New Hampshire bordering the Connecticut River. 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"). Connecticut Valley no longer conducts business as an electric utility in New Hampshire. See New Hampshire Retail Rates below for additional information.

The Company owns 47.02 percent of the common stock and 48.03 percent of the preferred stock of Vermont Electric Power Company, Inc. ("VELCO"). 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. See Transmission below for additional information.

The Company owns 58.85 percent of the common stock of Vermont Yankee Nuclear Power Corporation ("VYNPC"), which 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, VYNPC completed the sale of its nuclear power plant to Entergy Nuclear Vermont Yankee, LLC ("ENVY"). VYNPC administers the purchased power contracts among the former plant owners and ENVY. See Power Resources below for additional information.

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. See Nuclear Decommissioning Costs below for additional information.

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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 ("Custom"), which was formed for the purpose of holding passive investments, including the stock of the Company's subsidiaries that invest in regulated business opportunities. On October 13, 2003, the Company transferred its shares of VYNPC to Custom. The transfer to Custom does not affect the Company's rights and obligations related to VYNPC.

The Company is subject to the regulatory authority of the Vermont Public Service Board ("PSB") with respect to rates and terms of service, and the Company and VELCO are subject to PSB jurisdiction related to securities issues, planning and construction of major generation and transmission facilities and various other matters. 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, a 1155 MW nuclear generating facility, respectively.

The Company was subject to the regulatory authority of the New Hampshire Public Utilities Commission ("NHPUC"), through its wholly owned subsidiary Connecticut Valley, with respect to rates, securities issues and various other matters. On January 1, 2004, substantially all of Connecticut Valley's plant assets and its franchise were sold to PSNH. See discussion of New Hampshire Rates 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 is in the process of re-licensing or preparing to re-license six separate hydro-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 the Company's hydroelectric nameplate capacity. The Company has obtained an exemption from licensing for the Bradford and East Barnet projects.

Although the Company, by reason of its ownership of utility subsidiaries, 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.

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The Company cannot presently forecast the costs or other effects that environmental regulation may ultimately have on its existing and proposed facilities and operations. The Company believes that any such prudently incurred costs related to its utility operations would be recoverable through the ratemaking process. For additional information see Part II Item 8, Note 13, herein for disclosures relating to environmental contingencies, hazardous substance releases and the control measures related thereto.

The nuclear generating facilities 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 New England has implemented its version of FERC's "standard market design" ("SMD"), which is a detailed competitive market framework that has resulted in bid-based competition of power suppliers rather than prices set under cost of service regulation. Similar versions of SMD have been implemented in New York State and a large abutting multi-state region referred to as PJM. 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. Another competitive threat is the potential for customers to form municipally owned utilities in the Company's service territory.

Pursuant to Vermont statute (30 V.S.A. Section 249), the PSB has established as the service area for the Company in which it currently operates. 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 that it is appropriate. The PSB assesses the following factors in reaching its conclusion: (1) the need for the sale, (2) the rates are just and reasonable, (3) the sale will result in economic benefit, (4) the sale will not adversely affect system stability and reliability and (5) the sale will be in the best interest of ratepayers.

Section 212(d) provides that upon PSB approval of a 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 by the PSB after a hearing, if the parties fail to reach an agreement. 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. In one instance, the Town of Springfield acted to acquire the Company's distribution facilities in that community pursuant to a vote in 1977; that action was discontinued in 1985. The other instance, which occurred in 2002, involved the Town of Rockingham, which voted to pursue purchase of the Company's distribution facilities, Green Mountain Power's ("GMP") distribution facilities, and USGen's

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hydroelectric facility located in Bellows Falls. The Company and GMP refused to voluntarily sell their distribution facilities. In November 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 in December 2003 obtained a permanent injunction from the Superior Court prohibiting Rockingham from pursuing this course of action. If Rockingham decides to continue this action, in the future, it must proceed with the PSB under Title 30. The Company currently serves about 260 residential and small general service customers in Rockingham, whose usage amounts to substantially less than one percent of the Company's annual retail sales.

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

In the large commercial and industrial sectors, cogeneration and self-generation are the major competitive threats to network electric sales. Competitive risks in these market segments are primarily related to seasonal, one-shift milling operations that can tolerate periodic power outages common to such forms of cogeneration or self-generation, and for industrial or institutional customers with steady heat loads where the generator's waste heat can be used in their manufacturing or space conditioning processes. Competitive advantages for electricity in those segments are cost stability; convenience; cost of back-up power sources or alternatively, reliability; space requirements; noise problems; air emission and site 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 for power supply services 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 continues to examine changes to the provision of electric service absent introduction of retail choice. See PART II Item 7 for a discussion of Energy Initiatives in Vermont, and Wholesale Rates below, for a discussion of the Company's wholesale electric business.

Vermont Retail Rates

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, which included 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: In April 2003, the Company filed cost of service studies for rate years 2003 and 2004, in accordance with the PSB's approval of the Vermont Yankee sale. The purpose 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 agreed to a Memorandum of Understanding ("MOU") with the DPS regarding that filing. The MOU 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 allowed 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 in connection with the Connecticut Valley sale to write down deferred charges.

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On February 3, 2004, the Company filed a Request for Reconsideration and Clarification, and in March 2004 participated in a workshop to review the filing. On April 7, 2004, the PSB denied the Company's request. While the PSB agreed to remove the third modification, absent the Company's acceptance of the remaining modifications, the PSB concluded that it would open a rate investigation. Consequently, the PSB issued an Order Opening Investigation and Notice of Prehearing Conference in Docket No. 6946 to investigate the Company's current rates.

2004 Retail Rate Case: On July 15, 2004, the Company filed a cost of service in the rate investigation that demonstrated a rate deficiency of 2.4 percent, and recommended that rates should not be decreased retroactively to April 1, 2004. Also on July 15, 2004, the Company filed its request with the PSB for a 5.01 percent rate increase, to be effective April 1, 2005, and requested that the two cases be consolidated. On September 8, 2004, the PSB consolidated the two cases and confirmed a schedule for proceedings through 2004, with a final order in March 2005.

On October 1, 2004, the DPS filed its testimony with the PSB related to the rate investigation and the request for a rate increase. The DPS's major findings and recommendations included: 1) a rate refund to ratepayers retroactive to April 1, 2004 of 4.65 percent or $12 million; and 2) a rate reduction of 5.93 percent or almost $16 million on an annual basis effective with service rendered April 1, 2005. On October 1, 2004, AARP, an intervener in the case, filed testimony that supported a rate increase of up to 3.5 percent effective April 1, 2005. Technical hearings with the PSB began in early November 2004. Hearings and filings continued through February 2005.

In filings with the PSB on February 11 and 16, 2005, the DPS suggested: 1) a rate refund or credit to the Company's ratepayers retroactive to April 1, 2004 of about 6 percent or $16 million; and 2) a rate reduction of about 7 percent or $19 million effective with service rendered April 1, 2005. While supporting the DPS position, AARP proposed the following modifications: 1) allow a 10 percent return on equity (the DPS recommended 8.75 percent); 2) amortize deferred debits over a six-year period (the DPS recommended a three-year period); and 3) exclude the costs associated with or resulting from the Connecticut Valley asset sale from the Company's cost of service.

On February 18, 2005, the PSB approved the Company's request for an Accounting Order that, among other things, allowed for deferral of certain 2004 utility earnings. The approved Accounting Order permitted the Company to record in other regulatory liabilities any earnings achieved by the utility in excess of the 11 percent return on equity. The earnings to be deferred were calculated by the same method the Company used for determining and reporting earnings for 2001, 2002 and 2003 under the mandated earnings cap of 11 percent per the July 2001 PSB-approved rate order. In 2004, utility earnings above the 11 percent return on equity amounted to $3.8 million pre-tax and the resulting regulatory liability will be accounted for as determined by the PSB in its final order. The issuance of the Accounting Order does not create any expectations, set any precedent, or in any other way impair the PSB's ability to rule on the contested issues in the rate case.

The DPS opposed the Company's request for an Accounting Order and expressed concern that PSB approval of the Accounting Order would create the perception that regulators supported the Company's proposed 11 percent return on equity and the method for calculating the earnings cap for the 2001 to 2003 period. The DPS suggested alternative methods to mitigate the financial impacts of a potential adverse decision. Those alternatives were not accepted by the PSB. However, the PSB's approval of the Accounting Order made clear that the 11 percent return on equity and the method for calculating over earnings for the period of 2001 to 2003 are in dispute in the rate proceedings and that the Accounting Order does not decide these issues.

The last PSB hearing was held on February 18 and the parties filed reply briefs on February 28, 2005. The Company's February 28, 2005 reply brief demonstrates that a reduction in the Company's rates for the period April 1, 2004 through March 31, 2005 would not be just or reasonable. Instead a modest increase (about 2.9 percent) in the Company's rates beginning April 1, 2005 is justified. The Company based its conclusion on the terms of the power cost settlement reached with the DPS and application of the $3.8 million deferred 2004 earnings to reduce deferred charges eligible for recovery in rates. Both of these items require approval by the PSB. A final decision from the PSB is expected on March 25, 2005. The Company cannot predict the outcome of the rate case at this time.

New Hampshire Retail Rates

Prior to the January 1, 2004 sale described below, Connecticut Valley's retail rate tariffs were approved by the NHPUC, and contained a Fuel Adjustment Clause and a Purchased Power Cost Adjustment. Under these clauses, Connecticut Valley recovered its estimated annual costs for purchased energy and capacity; these estimates were reconciled annually when actual data was available.

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Connecticut Valley Sale: On January 1, 2004, Connecticut Valley completed the sale of substantially all of its plant assets and its franchise to PSNH. The sale, including termination of the power contract between the Company and Connecticut Valley, resolved all Connecticut Valley restructuring litigation in New Hampshire and the Company's stranded cost litigation at FERC.

Cash proceeds from the sale amounted to about $30 million, with $9 million representing the net book value of Connecticut Valley's plant assets plus certain other adjustments, and $21 million as described below. In return, PSNH acquired Connecticut Valley's franchise, poles, wires, substations and other facilities, and several independent power obligations.

The assets and liabilities of Connecticut Valley are classified as held for sale in the Company's Consolidated Balance Sheets in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. The results of operations related to Connecticut Valley are reported as discontinued operations for all periods presented, and certain of the Company's common corporate costs, which were previously allocated to Connecticut Valley, were reallocated back to continuing operations to reflect the sale's impact on continuing operations. 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 to PSNH.

As a condition of the sale, Connecticut Valley paid the Company $21 million to terminate its long-term power contract. In accordance with SFAS No. 5, in the first quarter of 2004, the Company recorded a $14.4 million pre-tax loss accrual related to termination of the power contract. The loss accrual represents Management's best estimate of the difference between expected future sales revenue, in the wholesale market, for the purchased power that was formerly sold to Connecticut Valley and the cost of purchased power obligations. See Part II Item 7 for additional information regarding the loss accrual.

For accounting purposes, components of the sale transaction are recorded in both continuing and discontinued operations in the Consolidated Statement of Income. In 2004, income from discontinued operations included a gain on disposal of about $21 million, pre-tax, or $12.3 million, after-tax, reflecting the $30 million payment from PSNH, net of various other adjustments. In addition to the gain on disposal of discontinued operations, the Company recorded a loss on power costs, net of tax, of $8.4 million relating to termination of the power contract with Connecticut Valley. The loss is included in Purchased Power on the Consolidated Statement of Income. When the two accounting transactions are combined to assess the total impact of the sale, the result is a gain of $3.9 million recorded in 2004.

On January 1, 2004, Connecticut Valley also paid in full a $3.8 million inter-company promissory note due to the Company. There are no remaining significant business activities related to Connecticut Valley.

Wholesale Rates 

Prior to January 1, 2004, the Company sold firm power to Connecticut Valley under a wholesale rate schedule based on forecast data for each calendar year, which was 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. The long-term contract under which the Company sold power to Connecticut Valley was terminated by Connecticut Valley as a result of the January 1, 2004 sale described above.

The Company provides wholesale transmission service to nine network customers and two point-to-point customers under its FERC Open Access Transmission Service Tariff No. 7, and to four network customers under two FERC rate schedules. One interconnection request is in process under Tariff No. 7. The Company maintains an OASIS site for transmission on the ISO-New England web page. Effective February 1, 2005, Tariff No. 7 was succeeded by ISO-New England FERC Electric Tariff No. 3, Section II - Open Access Transmission Tariff as Schedule 21-CV.

Rochester Electric Light and Power is the only remaining customer taking wholesale power service under Rate R-12 of FPC Electric Tariff, First Revised Volume No. 1. New Hampshire Electric Cooperative, Inc. and Woodsville Fire District Water and Light Department take wholesale power service under FERC Electric Tariff, Original Volume No. 8.

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The Company's energy generation and purchased power required to serve retail and firm wholesale customers was 2,423,227 mWh for the year ended December 31, 2004, compared to 2,552,827 mWh for the year ended December 31, 2003. The maximum one-hour integrated demand during that period was 426.5 MW, which occurred on December 27, 2004, compared to 417.2 MW, which occurred on December 2, 2003. Total energy generation and purchased power in 2004, including that related to all resale customers, was 2,928,450 mWh.

The following table shows the sources of such energy and capacity available to the Company for the year ended December 31, 2004. For additional information related to purchased power, refer to PART II Item 7.

The Company's wholly owned plants are located in Vermont, and have a combined nameplate capacity of about 73.6 MW. The Company owns and operates all of these plants which include 1) 20 hydroelectric generating facilities with nameplate capacities ranging from a low of about 0.2 MW to a high of about 7.5 MW, for an aggregate nameplate capacity of 44.7 MW; 2) two oil-fired gas turbines with a combined nameplate capacity of 26.4 MW, and 3) one diesel-peaking unit with a nameplate capacity of 2.6 MW.

The Company's joint-ownership interests in generating and transmission plants are shown in the table below. The Company is responsible for its share of the operating expenses of these facilities.

The Company receives its share of output and capacity of Millstone Unit #3, a 1155 MW nuclear generating facility; Wyman #4, a 615 MW generating facility and Joseph C. McNeil, a 53 MW generating facility, as shown in the table above.

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. See Pat II Item 7 for additional information.

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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, 2004, the Company's obligation is about 46 percent of the total VJO Power Contract through 2016, which translates to about $663 million, on a nominal basis. The average annual amount of capacity that the Company will purchase from January 1, 2005 through October 31, 2012 is about 144.4 MW, with lesser amounts purchased through October 31, 2016. See Part II Item 7 and Item 8, Note 13, for additional information regarding the Hydro-Quebec contract.

VYNPC The Company has a 35 percent entitlement in Vermont Yankee plant output sold by Entergy Nuclear Vermont Yankee, LLC ("ENVY") to VYNPC, through a long-term power purchase ("PPA") contract with VYNPC. One remaining secondary purchaser continues to receive a small percentage of the Company's entitlement, reducing it to entitlement to about 34.83 percent. The long-term contracts between VYNPC and the entitlement holders and between VYNPC and ENVY became effective on July 31, 2002, the same day that the plant was sold to ENVY. The Company no longer bears the operating costs and risks associated with running the plant or the costs and risks associated with the eventual decommissioning of the plant. ENVY has no obligation to supply energy to VYNPC over the amount the plant is producing, so entitlement holders receive reduced amounts of energy when the plant is operating at a reduced level, and no energy when the plant is not operating.

The PPA through which VYNPC purchases power from ENVY and in turn sells to its sponsors includes prices that range from 3.9 cents to 4.5 cents per kilowatt-hour through March 2012. Effective November 2005, the contract prices are subject to a "low-market adjuster" that protects the Company and its 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 12-month average (ending in same billing month) of hourly market prices as defined in the PPA. If the 12-month average market price is less than 95 percent of the base PPA contract price, then 105 percent of the 12-month average market price will be used for the billing month. The low-market adjusted price cannot exceed the base PPA contract price. If market prices rise, however, contract prices are not adjusted upward. In addition to PPA charges, VYNPC's billings to the sponsors include certain of its residual costs of service through a FERC tariff to the VYNPC 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.

Nuclear industry practice typically is to maintain the capacity to off-load the entire active nuclear fuel core into the spent fuel pool as a safety measure; this is called maintaining full core discharge capability. ENVY anticipated that to maintain full core discharge capability, dry cask storage of spent nuclear fuel will be needed at the Vermont Yankee plant by late 2008 based on current operations or as early as 2007 if the NRC does grant permission to uprate the plant output. ENVY requires enabling legislation from the Vermont State Legislature and PSB approval for dry cask storage. See Part II Item 7, and Item 8, Note 13, for additional information regarding VYNPC.

Cogeneration/Independent Power Qualifying Facilities The Company purchases power from several Independent Power Producers ("IPPs") who own qualifying facilities under the Public Utilities Regulatory Policies Act of 1978. These facilities primarily use water and biomass as fuel. Most of the power comes through a state-appointed purchasing agent, which assigns power to all Vermont utilities under PSB rules. In 2004, total IPP purchases accounted for 6.8 percent of the Company's total mWh purchased and 12.2 percent of purchased power costs. See Part II Item 8, Note 13, for additional information.

NEPOOL and ISO-New England The Company is a participant in the New England Power Pool ("NEPOOL"), a regional bulk power transmission organization established to assure reliable and economical power supply in the Northeast United States. NEPOOL 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

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the competitive wholesale electricity marketplace. A 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 NEPOOL to the new organization. ISO-New England has a service contract with NEPOOL to operate the bulk power system and to administer the wholesale marketplace.

Beginning May 1, 2004, the Company began to settle its power accounts with ISO-New England on a standalone (direct) basis. Up until this time, all Vermont utilities were settled at ISO-New England, and VELCO then performed the settlement for each utility in Vermont. With changes in power markets and NEPOOL/ISO rules and procedures, many of the benefits of a single Vermont settlement have disappeared, and direct settlement now provides advantages to the Company in terms of efficiency and cost savings. Hourly purchases and sales through ISO-New England are described in Short-term Purchases and Sales below.

ISO-New England is governed by FERC, under rules defined by NEPOOL and approved by FERC. These rules 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 efficient management and reliable operation of the regional bulk power system. In March 2003, ISO-New England moved to SMD, a significant step to restructuring the wholesale energy markets in the Northeast.

NEPOOL's peak for 2004 occurred on August 30, 2004 and totaled 24,116 MW. The Company's peak demand occurred on December 27, 2004 and totaled 426.5 MW, and the Company had a reserve margin of about 8.49 percent at the time.

Short-term Purchases and Sales 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. Such short-term purchases and sales are not considered energy trading activities. The Company enters into forward purchase contracts when additional supply is needed, such as for a Vermont Yankee nuclear plant refueling outage. The Company enters into forward sale contracts when it forecasts excess supply and to minimize the net cost and risks of serving customers. On an hourly basis, power is sold or bought through ISO-New England's settlement process to balance the Company's resource output and load requirements. On a monthly basis, the Company aggregates the hourly sales and purchases through ISO-New England and records them as Operating Revenue or Purchased Power, respectively.

The Company's long-term power forecast shows that energy purchase and production amounts exceed its load requirements. This is partly attributed to the January 1, 2004 termination of the power contract with Connecticut Valley, which made an annual average of about 15 MW previously used to source the contract available for load requirements or for resale. Because of this general increase, in November 2004, the Company entered two separate forward sale transactions, one through October 2006 and one through December 2008. Both contracts require physical delivery of power, but one is contingent upon Vermont Yankee plant output.

Based on existing commitments and contracts, the Company expects that net purchased power and production fuel costs will average about $122 million to $132 million per year for the years 2005 through 2009. These projections are dependent, in part, upon wholesale power market prices. Increases in the wholesale price should generally reduce net power costs, while decreases should generally increase net costs.

Derivative Financial Instruments 

The Company accounts for various power contracts as derivatives under the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted (collectively "SFAS No. 133"), which requires that derivatives be recorded on the balance sheets at fair value.

The Company's long-term contracts for the purchase of power from VYNPC and IPPs do not meet the definition of a derivative under the requirements of SFAS No. 133 because delivery of power under these contracts is contingent on plant output. Additionally, the long-term power contract with Hydro-Quebec does not meet the definition of a derivative because there is no defined notional amount.

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The Company has a long-term purchased power contract that allows the seller to repurchase specified amounts of power with advance notice (Hydro-Quebec Sellback #3). This contract has been determined to be a derivative under SFAS No. 133.  The derivative's year-end estimated fair value was an unrealized loss of $5.7 million in 2004 and an unrealized loss of $1.2 million in 2003. The estimated fair value of this derivative is valued using a binomial tree model, and quoted market data when available along with appropriate valuation methodologies.

The Company has assessed the two forward sale contracts it entered into in November 2004 and determined that one is a derivative under SFAS No. 133, and the other, due to its unit contingent nature, is not a derivative. The derivative contract is for delivery of about 15 MW per hour, or a total of 522,544 mWh for the contract term, which extends from November 17, 2004 through December 31, 2008. At December 31, 2004, this contract had an estimated fair value of a $0.4 million unrealized gain. The Company utilized over-the-counter quotations or broker quotes at December 31, 2004 for determining the fair value of this contract.

The Company records derivative contracts on the Consolidated Balance Sheets at fair value. Based on a PSB-approved Accounting Order, the Company records the change in fair value of these derivatives as deferred charges or deferred credits on the balance sheet, depending on whether the fair value is an unrealized loss or gain.

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 As a joint owner of the Millstone Unit #3 facility, in which Dominion Nuclear Corporation ("DNC") is the lead owner with about 93.47 percent of the plant joint-ownership, the Company is responsible for its share of nuclear decommissioning costs. The Company has an external trust dedicated to funding its joint-ownership share of future decommissioning costs. DNC has suspended contributions to the Millstone Unit #3 Trust Fund because the minimum NRC funding requirements are being met or exceeded. The Company has also suspended contributions to the Trust Fund, but could choose to renew funding at its own discretion as long as the minimum requirement is met or exceeded. If a need for additional decommissioning funding is necessary, the Company will be obligated to resume contributions to the Trust Fund.

In January 2004, DNC filed, on behalf of itself and the two minority owners, including the Company, a lawsuit against the United States Department of Energy ("DOE") seeking recovery of costs related to storage of spent nuclear fuel arising from the failure of the DOE to comply with its obligations to commence accepting such fuel in 1998. The schedule for further proceedings in the lawsuit is not known at this time. Millstone Unit #3 spent fuel from the beginning of commercial operations in 1986 resides in the spent fuel pool, and there is believed to be adequate spent fuel pool storage capability to support expected operations through the end of its current licensed life in 2025. The Company continues to pay its share of the DOE Spent Fuel assessment expenses levied on actual generation and will share in recovery from the lawsuit, if any, in proportion to its ownership interest.

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Maine Yankee, Connecticut Yankee and Yankee Atomic These nuclear plants have been shut down and are undergoing decommissioning. Information related to decommissioning and closure costs, including the Company's share of estimated future payments 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 DOE under the 1983 fuel disposal contracts that were mandated by the United States Congress under the High Level Waste Act. All three are parties to a lawsuit against the DOE seeking damages based on the DOE's default. The trial on determination of damages began on July 12 and ended August 31, 2004. Closing arguments were held in January 2005 and final post-trial briefs were filed in February 2005. A decision is expected by the end of 2005; however, an appeal by at least one of the parties is likely. None of the plants has included any allowance for potential recovery of these claims in their FERC-filed cost estimates.

The Company's share of Maine Yankee, Connecticut Yankee and Yankee Atomic estimated costs are reflected on the Consolidated Balance Sheets as regulatory assets or other deferred charges, and nuclear decommissioning liabilities (current and non-current). These amounts are adjusted when revised estimates are provided by the companies. At December 31, 2004, the Company had regulatory assets of about $5.8 million related to Maine Yankee and $2.1 million related to Connecticut Yankee. These estimated costs are being collected from the Company's customers through existing retail rate tariffs. At December 31, 2004, the Company also had other deferred charges related to incremental dismantling costs of about $10.5 million for Connecticut Yankee and $7.2 million for Yankee Atomic. These amounts include payments of about $0.1 million to Connecticut Yankee and $3 million to Yankee Atomic, representing the Company's share of the respective companies' collection of incremental costs as of December 31, 2004. These i ncremental dismantling costs are not being recovered through existing retail rate tariffs, and are being deferred based on an October 2003 PSB-approved Accounting Order for treatment of these incremental costs as deferred charges, to be addressed in the Company's pending rate proceeding.

Maine Yankee, Connecticut Yankee and Yankee Atomic collect decommissioning and closure costs through wholesale FERC-approved rates charged under power agreements with several New England utilities, including the Company. Historically, the Company's share of these costs has been recovered from its retail customers through PSB-approved rates. Based on the regulatory process, management believes its share of decommissioning and closure costs for each plant will continue to be recovered through the regulatory process. Although Management believes that the decommissioning and closure costs will ultimately be recovered from its customers, there is a risk that FERC may not allow full recovery of Connecticut Yankee's incremental increased costs in wholesale rates. If FERC does not allow these costs to be recovered in wholesale rates, the Company anticipates that the PSB would disallow these costs for recovery in retail rates as well. See discussion below for additional information related to Maine Yankee, Co nnecticut Yankee and Yankee Atomic.

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Maine Yankee: The Company has a 2 percent ownership interest in Maine Yankee. Billings from Maine Yankee to the Company amounted to about $1.3 million in 2004, $1.1 million in 2003 and $1.1 million in 2002, and are included in Purchased Power on the Consolidated Statements of Income. Accounts Payable to Maine Yankee for 2004 and 2003 were of a nominal amount. In October 2003, Maine Yankee filed a FERC rate proceeding for collection of estimated decommissioning and long-term spent fuel storage costs. In July 2004, Maine Yankee and various other parties agreed to an Offer of Settlement resolving all issues raised by the rate case participants. On September 16, 2004, FERC approved the settlement, which provides for recovery of all of Maine Yankee's forecasted costs of providing service through a formula rate contained in its power contracts through October 31, 2008 and replenishment of the DOE Spent Fuel Obligation through collections from November 2008 through October 2010.

From January 1 through October 31, 2004, Maine Yankee's billings to sponsor companies were based on its FERC filing subject to refund. Beginning November 1, 2004, Maine Yankee's billings have been based on the FERC-approved settlement, reduced for excess collections that occurred prior to the effective date.

Connecticut Yankee: The Company has a 2 percent ownership interest in Connecticut Yankee. Billings from Connecticut Yankee to the Company amounted to $0.9 million for 2004, $0.9 million for 2003 and $0.9 million for 2002, and are included in Purchased Power on the Consolidated Statements of Income. Accounts Payable to Connecticut Yankee for 2004 and 2003 were of a nominal amount. Costs currently billed by Connecticut Yankee are based on its most recent FERC-filed rates, which became effective February 1, 2005, for collection through 2010, subject to refund, and pending a final order by FERC. Prior to February 1, 2005, costs were billed by Connecticut Yankee based on its FERC-approved rates that became effective September 1, 2000, for collection through 2007.

Connecticut Yankee is currently involved in litigation related to a contract dispute. Also in 2004, Connecticut Yankee filed a rate application with FERC. These matters are discussed in more detail below.

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The Company's estimated aggregate obligation related to Connecticut Yankee is about $12.6 million. The Company continues to believe that FERC will approve recovery of these increased costs in wholesale rates based on the nature of costs and previous rulings at other nuclear companies. Once approved by FERC, the Company believes it is unlikely that the PSB would not allow these FERC-approved costs to be recovered in retail rates. If FERC adopts the CT DPUC's recommendations described above, the Company's share of the proposed disallowance would be about $4.7 million. The timing, amount and outcome of the Bechtel litigation and FERC rate case filing cannot be predicted at this time.

Yankee Atomic: The Company has a 3.5 percent ownership interest in Yankee Atomic. Billings from Yankee Atomic to the Company amounted to $1.9 million for 2004 and $1.1 million for 2003, and are included in Purchased Power on the Consolidated Statements of Income. Accounts Payable to Yankee Atomic for 2004 and 2003 were of a nominal amount. Billings from Yankee Atomic 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 April 2003, Yankee Atomic filed with FERC, based on updated cost estimates, 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. On August 6, 2003, Yankee Atomic filed a Settlement Agreement that resolved all issues raised by the parties. Beginning April 2004 and each year following, the new rates are subject to an annual adjustment based on the prior calendar year's data if the decommissioning trust fund market performance is 10 percent greater or 10 percent less than the assumptions used to calculate the schedule of decommissioning charges. As such, a reduction was applied to filed-rates beginning with April 2004 billings.

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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, but renewal of the law is still being considered as part of comprehensive energy legislati on. The liability coverage purchased by existing commercial nuclear power plants under the Act is not 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.

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 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 48.5 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 48.03 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 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.

Transmission plays a significant role in the competitive wholesale 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 NEPOOL for shared cost treatment. Vermont has traditionally had higher-than-average transmission costs. The current approach provides cost and reliability benefits in providing service to our customers, because our load share is a small fraction of New England's load, and the facilities upgrades VELCO is planning improve the reliability and efficiency of the transmission network. The Company will pay a share of such projects elsewhere in New England, but the net economic effect is expected to be beneficial. Also, better reliability elsewhere in the region benefits Vermont's reliability because of the highly integrated nature of New England's high-voltage network. If other future transmiss ion facilities do not qualify for cost sharing, those costs will be charged only to the requesting entity and the Company's share of such costs will be affected by FERC approved cost-allocation rules contained in VELCO's and our tariffs and agreements.

At December 31, 2004, VELCO has authorized 430,000 shares of Class B common stock, $100 par value, of which 214,960 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, four issues of First Mortgage Bonds, aggregating $73,595,000 issued under an Indenture of Mortgage dated as of September 1, 1957, as amended, between VELCO and Duetsche Bank Trust Company Americas, as Trustee (the "VELCO Indenture") were authorized and outstanding at December 31, 2004. The issuance of bonds under the VELCO Indenture is unlimited in amount but is subject to certain restrictions.

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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 a majority of the shares of VELCO, 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, 2004) 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 England Electric Transmission Cor poration 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 were outstanding on December 31, 2004 and owned by VELCO, with each share having one vote. During 1986 VETCO paid off its construction financing by issuing $37,000,000 of secured notes, maturing in 2006, and receiving a $9,999,000 equity contribution from VELCO. The notes are secured by a First Mortgage on the major part of VETCO's transmission properties and by the assignment of its rights under the Support Agreements.

The Company participated with other electric utilities in the construction of the Phase I Hydro-Quebec interconnection transmission facilities in northeastern Vermont, which were completed at a total cost of about $140 million. Under a support agreement relating to 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 ending in 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 about $487 million. Under a similar support agreement, the New England participants, including the Company, 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 ending in 2015. These agreements meet the capital lease accounting requirements under SFAS No. 13, Accounting for Leases. All costs under these agreements are recorded as purchased transmission expense in accordance with the Company's ratemaking policies. See Part II Item 8, Note 13 for additional information regarding the future expected payments related to these agreements.

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.

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.

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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 constrained transmission or distribution areas; the Company has five such ASCs.

Catamount Resources Corporation was formed for the purpose of holding the Company's subsidiaries that invest in unregulated business opportunities. One of its subsidiaries, Catamount Energy Corporation, invests through its wholly owned subsidiaries in non-regulated energy generation projects in 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. On December 31, 2004 the Company and its wholly owned subsidiaries including Catamount, employed 550 persons, of which 221 are represented by the union. On December 29, 2004, the Company and its employees represented by the union agreed to a new four-year contract, which expires on December 31, 2008. The new contract provided for a net general wage increase of 3.5 percent effective January 2, 2005, January 1, 2006, December 31, 2006 and December 30, 2007. It also included an increase in the Company's 401K match from 4 to 4.5 percent beginning December 31, 2006 and an increase from 18 to 20 percent of employee contributions for health-care coverage beginning April 1, 2005.

The Company's kilowatt-hour sales and revenues are typically higher in the winter and summer than in the spring and fall as sales tend to vary with weather. Winter recreational activities, longer hours of darkness and heating loads from cold weather contribute to peaks in the winter, while air conditioning contributes to peaks in the summer. Consumption is least in the spring and fall when there is little heating or cooling load.

     CAPITAL EXPENDITURES

The Company's capital expenditures totaled about $20.2 million in 2004, $15 million in 2003 and $13.9 million in 2002. The Company's capital expenditures for the utility are expected to range from $60 million to $70 million for the 3-year period between 2005 and 2007. This estimate is subject to continuing review and adjustment and actual capital expenditures may vary from this estimate. For additional information regarding capital expenditures and working capital see Part II, Item 7.

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.

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Mr. Young joined the Company in 1987. He was elected Senior Vice President - Finance and Administration in 1988. He served as Executive Vice President and Chief Operating Officer (COO) commencing in 1993 and was elected Director, President and Chief Executive Officer (CEO) commencing in 1995. Mr. Young also serves as President, CEO, and Chair of the following CVPS subsidiaries: Connecticut Valley Electric Company Inc.; CVPSC - East Barnet Hydroelectric, Inc.; CV Realty, Inc.; Custom Investment Corporation; Catamount Resources Corporation; Eversant Corporation; AgEnergy, Inc.; SmartEnergy Water Heating Services, Inc.; and, Chair of Catamount Energy Corporation. He is also Director of the following CVPS affiliates: Vermont Electric Power Company, Inc., Vermont Yankee Nuclear Power Corporation; Vermont Electric Transmission Company, Inc.; and, The Home Service Store, Inc.

Mr. 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.

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: 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. Ms. Gibson serves as Director, Senior Vice President, Chief Financial Officer, and Treasurer for the following CVPS subsidiaries: Connecticut Valley Electric Company Inc.; 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 AgEnergy, Inc. and Senior Vice President and Chief Financial Officer of Catamount Energy Corporation, CVPS subsidiaries. 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.

Mr. Kraus joined the Company in 1981. Prior to being elected to his present position of Senior Vice President Operations, Engineering and Customer Service, 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: Connecticut Valley Electric Company Inc.; CVPSC - East Barnet Hydroelectric, Inc.; CV Realty, Inc.; Custom Investment Corporation; Catamount Resources Corporation; Eversant Corporation; AgEnergy, Inc.; and, SmartEnergy Water Heating Services, Inc.

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Mr. Rocheleau joined the Company in November 2003. Mr. Rocheleau serves as Director, Senior Vice President for Legal and Public Affairs, and Corporate Secretary for the following CVPS subsidiaries: Connecticut Valley Electric Company Inc.; 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 Director and Senior Vice President and General Counsel for Catamount Energy Corporation, a CVPS subsidiary. Prior to joining the Company, he served as Director and Attorney at Law from 1992 to 2003 with Downs Rachlin Martin, PLLC.

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, New England Power 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 1.7769 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 1.7303 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 7,888 miles of overhead distribution lines and about 360 miles of underground distribution lines, all of which are located in Vermont except for about 23 miles in New Hampshire and about two miles in New York.

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.

Substantially all of the Company's utility property and plant is subject to liens under the Company's First Mortgage Bonds. See Part II Item 8, Note 7, for more information related to the First Mortgage Bonds.

Connecticut Valley Prior to the January 1, 2004 sale described in New Hampshire Retail Rates above, Connecticut Valley's electric properties consisted of two principal systems in New Hampshire which were not interconnected; each system, however, was 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.

VELCO VELCO's properties consist of about 573 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 about 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.

Additional information with respect to the Company's properties is set forth under the caption "Power Resources" in Item 1 and is incorporated herein by reference.

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.

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

There were no matters submitted to security holders during the fourth quarter of 2004.

Item 5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases
                of Equity Securities.

(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, 2004, there were 8,223 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 2003. Cash dividends of $.23 per share were paid for all quarters of 2004.

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, 2004, the Common Stock Equity of the unconsolidated Company was 61 percent of total capitalization.

The Company's First Mortgage Bond indenture contains certain restrictions on the payment of cash dividends on capital stock and other Restricted Payments (as defined). This covenant limits 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 Section 5.09 of the Forty-Fourth Supplemental Indenture dated June 15, 2004; such definitions are based upon the unconsolidated financial statements of the Company. As of December 31, 2004, $99 million was available for such Restricted Payments.

(d) The information required by this item is included in Item 12, herein.

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     (1) Excluding current portion

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

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.

EXECUTIVE OVERVIEW
Our consolidated 2004 earnings were $23.8 million, or $1.90 per diluted share of common stock, compared to 2003 earnings of $19.8 million, or $1.53 per diluted share of common stock, and 2002 earnings of $19.8 million, or $1.53 per diluted share of common stock. In 2004, discontinued operations of Connecticut Valley Electric Company Inc. ("Connecticut Valley") contributed $12.3 million, or $1.00 per diluted share of common stock, to consolidated earnings. This reflects a $12.3 million after-tax gain related to the January 1, 2004 sale of Connecticut Valley's plant assets and franchise. In 2003, discontinued operations of Connecticut Valley contributed $1.4 million, or $.12 per diluted share of common stock, and it contributed $1.5 million, or $.13 per diluted share of common stock, in 2002. The primary drivers of consolidated earnings for the past three years are discussed in detail in Results of Operations below.

For accounting purposes, components of the Connecticut Valley transaction in 2004 are recorded in both continuing and discontinued operations in the consolidated statement of income. The gain on the asset sale, net of tax, totaled $12.3 million, but we recorded a loss on power costs, net of tax, of $8.4 million relating to termination of the power contract between us and Connecticut Valley. The loss is recorded as purchased power expense in the consolidated statement of income. When the two accounting transactions are combined to assess the total impact of the transaction, the result is a gain of $3.9 million, or $.31 per diluted share of common stock.

Key financial initiatives for the Company in 2004 included:

• Our request for a retail rate increase, discussed in Vermont Retail Rates;
• Refinancing Second Mortgage Bonds that matured on August 1, 2004, discussed in Liquidity and Capital Resources;
• Our continued investments in Vermont Electric Power Corporation, discussed in Liquidity and Capital Resources;
• Catamount's continued investments in wind energy projects and the sale of certain of its investments in non-wind energy projects, discussed in Diversification; and
• January 1, 2004 sale of substantially all of Connecticut Valley's plant assets and its franchise, discussed in Discontinued Operations.

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 regulatory bodies, including the pending rate investigation and rate case before the Vermont Public Service Board;
• performance of the Vermont Yankee nuclear power plant;
• effects of and changes in weather and economic conditions;
• volatility in wholesale power markets;
• 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.

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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 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, 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, and its activities were regulated by the New Hampshire Public Utilities Commission ("NHPUC"). Our wholly owned unregulated subsidiaries include: Catamount Energy Corporation ("Catamount"), which invests primarily in wind energy projects in the United States and United Kingdom; and Eversant Corporation ("E versant"), which operates a rental water heater business through its subsidiary, SmartEnergy Water Heating Services, Inc.

The Vermont utility operation is our core business. 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 revenue streams. However, the ability to increase our customer base is limited to growth within the service territory, which has been relatively 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. We sell any excess power we have in the wholesale markets administered by ISO-New England or to third parties in New England. Such sales help to mitigate overall power costs; but wholesale power market volatility can affect these mitigation efforts.

Our retail rates are set by the PSB after considering recommendations of Vermont's consumer advocate, the Vermont Department of Public Service ("DPS"). 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.

Vermont regulatory issues remain our top priority. On July 15, 2004, we made two separate filings with the PSB: 1) a cost of service filing in the PSB's rate investigation; and 2) a request for a 5.01 percent rate increase. We also continue to monitor several State initiatives, one of which could, over time, shift utility regulation away from cost-based regulation.

In 2004, we refinanced our $75 million Second Mortgage Bonds, which matured on August 1, 2004, by issuing $75 million of First Mortgage Bonds. The lower interest rates resulting from the refinancing will reduce annual interest expense by about $2 million on a pre-tax basis. During 2004, we invested $7 million toward VELCO's planned transmission upgrade projects. Investments are made in Catamount on a project level basis upon review and approval of the Company's Management and Board of Directors.

The Vermont utility continues to generate sufficient cash flow to support ongoing operations. However, the outcome of the current rate case could negatively impact the utility's ongoing cash flow. 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. See Liquidity and Capital Resources below for more detail regarding cash flow, investment opportunities and the bond refinancing.

VERMONT RETAIL RATES
Our current retail rates are based on a June 26, 2001 PSB Order approving a settlement with the DPS, which included 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 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 us to return up to $16 million to ratepayers if there is a merger, acquisition or asset sale that requires PSB approval.

In April 2003, we filed cost of service studies for rate years 2003 and 2004, in accordance with the PSB's approval of the Vermont Yankee sale. The purpose 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 Memorandum of Understanding ("MOU") with the DPS regarding that filing. The MOU concluded that: 1) a rate decrease was not warranted; 2) we would decrease our allowed

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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 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 allowed 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 in connection with the Connecticut Valley sale to write down deferred charges.

On February 3, 2004, we filed a Request for Reconsideration and Clarification, and in March 2004 participated in a workshop to review the filing. On April 7, 2004, the PSB denied our request. While the PSB agreed to remove the third modification, absent our acceptance of the remaining modifications, the PSB concluded that it would open a rate investigation. Consequently, the PSB issued an Order Opening Investigation and Notice of Prehearing Conference in Docket No. 6946 to investigate current rates.

On July 15, 2004, we filed a cost of service study in the rate investigation that demonstrated a rate deficiency of 2.4 percent, and recommended that rates should not be decreased retroactively to April 1, 2004. Also on July 15, 2004, we filed a request with the PSB for a 5.01 percent rate increase, expected to be effective April 1, 2005, and requested that the two cases be consolidated. On September 8, 2004, the PSB consolidated the two cases and confirmed a schedule for proceedings through 2004, with a final order in March 2005.

On October 1, 2004, the DPS filed its testimony with the PSB related to the rate investigation and our request for a rate increase. The DPS's major findings and recommendations included: 1) a rate refund to ratepayers retroactive to April 1, 2004 of 4.65 percent or $12 million; and 2) a rate reduction of 5.93 percent or almost $16 million on an annual basis effective with service rendered April 1, 2005. On October 1, 2004, AARP, an intervener in the case, filed testimony that supported a rate increase of up to 3.5 percent effective April 1, 2005. Technical hearings with the PSB began in early November 2004. Hearings and filings continued through February 2005.

In filings with the PSB on February 11 and 16, 2005, the DPS suggested: 1) a rate refund or credit to our ratepayers retroactive to April 1, 2004 of about 6 percent or $16 million; and 2) a rate reduction of about 7 percent or $19 million effective with service rendered April 1, 2005. While supporting the DPS position, AARP proposed the following modifications: 1) allow a 10 percent return on equity (the DPS recommended 8.75 percent); 2) amortize deferred debits over a six-year period (the DPS recommended a three-year period); and 3) exclude the costs associated with or resulting from the Connecticut Valley asset sale from our cost of service.

On February 18, 2005, the PSB approved our request for an Accounting Order that, among other things, allowed for deferral of certain 2004 utility earnings. The approved Accounting Order permitted us to record in other regulatory liabilities any earnings achieved by the utility in excess of the 11 percent return on equity. The earnings to be deferred were calculated by the same method we used for determining and reporting earnings for 2001, 2002 and 2003 under the mandated earnings cap of 11 percent per our July 2001 PSB-approved rate order. In 2004, utility earnings above the 11 percent return on equity amounted to $3.8 million pre-tax. We recorded this pre-tax amount as a regulatory liability, which will be accounted for as determined by the PSB in its final order. The issuance of the Accounting Order does not create any expectations, set any precedent, or in any other way impair the PSB's ability to rule on the contested issues in our rate case.

The DPS opposed our request for an Accounting Order and expressed concern that PSB approval of the Accounting Order would create the perception that regulators supported our proposed 11 percent return on equity and the method for calculating the earnings cap for the 2001 to 2003 period. The DPS suggested alternative methods to mitigate the financial impacts of a potential adverse decision. Those alternatives were not accepted by the PSB. However, the PSB's approval of the Accounting Order made clear that the 11 percent return on equity and the method for calculating overearnings for the period of 2001 to 2003 are in dispute in the rate proceedings and that the Accounting Order does not decide these issues.

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The last PSB hearing was held on February 18 and the parties filed reply briefs on February 28, 2005. Our February 28, 2005 reply brief demonstrates that a reduction in rates for the period April 1, 2004 through March 31, 2005 would not be just or reasonable. Instead a modest increase (about 2.9 percent) in our rates beginning April 1, 2005 is justified. We based our conclusion on the terms of the power cost settlement reached with the DPS and application of the $3.8 million deferred 2004 earnings to reduce deferred charges eligible for recovery in rates. Both of these items require approval by the PSB. A final decision from the PSB is expected on March 25, 2005. We cannot predict the outcome of the rate case at this time.

The State of Vermont continues to examine changes to the provision of electric service absent introduction of retail choice. The following discussion highlights initiatives of potential significance.

Renewable Portfolio Standard In 2003 and 2004 several bills were introduced in the Vermont General Assembly to establish a Renewable Portfolio Standard ("RPS") requirement. The introduction of an RPS could require that we purchase certain amounts of our energy supply requirement from new renewable sources while maintaining existing renewable power content. Although none of those bills were enacted into law, there remains an interest in RPS, and several proposals have been introduced in the 2005 legislative session. These proposals are similar to a proposal in the PSB's 2004 report to the Vermont General Assembly. Based on activity in the current legislative session, we expect that a mandatory RPS, in some form, will be approved.

Renewable Pricing Programs Beginning in 2003, the Vermont General Assembly authorized the establishment of utility-sponsored renewable pricing programs to permit customers to voluntarily elect to 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 customers' 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 under its PSB-approved Integrated Resource Plan. Our first renewable pricing program, "CVPS Cow Power^TM," was approved by the PSB on July 30, 2004. The program promotes the production of renewable energy from cow manure from certain Vermont farms, and was made available to customers for energy use starting September 1, 2004. Pricing for the program is in the form of a premium relative to the tariff that would otherwise appl y. The premium is cost-based so that it reasonably reflects the difference between acquiring the renewable energy and our alternative cost of power. The program also requires that any costs of power in excess of our alternative cost of power be borne by those customers participating in the program. By year end, about 900 customers had signed up for CVPS Cow Power^TM.

Alternative Forms of Regulation In 2003, the Vermont General Assembly authorized alternative forms of regulation for electric utilities that, besides other criteria, establish a reasonably balanced system of risks and rewards to encourage utilities to operate as efficiently as possible. The PSB may only approve an alternative regulation plan if it finds that the plan will not adversely affect 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. At this time, we have not sought authorization to implement an alternate form of regulation.

Regulatory Risk On July 15, 2004, we made two separate filings with the PSB: 1) a cost of service in the PSB's rate investigation; and 2) a request for a 5.01 percent rate increase. These matters are discussed in more detail above.

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, such as 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. The Company currently complies with the provisions of SFAS No. 71 for its 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 $38.9 million on a pre-tax basis as of December 31, 2004, assuming no stranded cost recovery w ould be allowed through a rate mechanism.

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Although not currently under consideration, if retail competition were 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 ("VYNPC"). These contracts support the majority 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 overall net power costs and price risk. 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. These are discussed in more detail in Power Supply Matters below.

Inflation The annual rate of inflation, as measured by the Consumer Price Index, was 2.7 percent for 2004, 2.3 percent for 2003 and 1.6 percent for 2002. 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 Catamount is wholly focused on the development, ownership and asset management of wind energy projects. Catamount's future success is dependent on continued 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 - Generation of electricity by wind energy projects is highly dependent upon wind conditions at the site. 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 resources at any one site. In addition, average wind speeds and resources can vary widely in any year, resulting in significant annual revenue variability.
• Power Purchase Agreement Risk - Catamount will only invest in wind power projects that have power purchase agreements in place with acceptable third parties. The creditworthiness of such acceptable third parties varies and can result in risk to Catamount. Additionally, competitive bidding generally has reduced the price utilities pay independent power producers, which, in turn, reduces the profitability of many independent power projects.
• Wind Turbine Generator Technology Risk - Wind turbine generators ("WTGs") of the size Catamount intends to utilize have only been commercially available for three or four 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 the demise of major wholesale power marketing companies, have increased credit concerns in the energy industry specifically with unregulated energy companies. Obtaining or renewing corporate credit facilities is challenging and there is no guarantee credit will either be extended or renewed. Catamount terminated its credit facility in May 2004. Catamount solicits, as needed, 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.

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• 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 us.
  

Also see Quantitative and Qualitative Disclosures About Market Risk for additional information related to market risk associated with our regulated utility business.

On January 1, 2004, Connecticut Valley completed the sale of substantially all of its plant assets and its franchise to PSNH. The sale, including termination of the power contract between us and Connecticut Valley, resolved all Connecticut Valley restructuring litigation in New Hampshire and our stranded cost litigation at FERC.

Cash proceeds from the sale amounted to about $30 million, with $9 million representing the net book value of Connecticut Valley's plant assets plus certain other adjustments, and $21 million as described below. In return, PSNH acquired Connecticut Valley's franchise, poles, wires, substations and other facilities, and several independent power obligations.

As a condition of the sale, Connecticut Valley paid us $21 million to terminate its long-term power contract. In accordance with SFAS No. 5, Accounting for Contingencies ("SFAS No. 5"), in the first quarter of 2004, we recorded a $14.4 million pre-tax loss accrual related to termination of the power contract. The loss accrual represented Management's best estimate of the difference between expected future sales revenue, in the wholesale market, for the purchased power that was formerly sold to Connecticut Valley and the cost of purchased power obligations. See discussion of Reserve for Loss on Power Contract in Critical Accounting Policies below.

For accounting purposes, components of the sale transaction are recorded in both continuing and discontinued operations in the Consolidated Income Statement. In 2004, income from discontinued operations included a gain on disposal of discontinued operations of about $21 million, pre-tax, or $12.3 million, after-tax, reflecting the $30 million payment from PSNH, net of various other adjustments. In addition to the gain on disposal, we recorded a loss on power costs, net of tax, of $8.4 million relating to termination of the power contract with Connecticut Valley as described above. The loss is included in Purchased Power on the Consolidated Statement of Income. When the two accounting transactions are combined to assess the total impact of the sale, the result is a gain of $3.9 million recorded in 2004.

On January 1, 2004, Connecticut Valley also paid in full a $3.8 million inter-company promissory note that was payable to us. There are no remaining significant business activities related to Connecticut Valley. Summarized results of operations of the discontinued operations are as follows (in thousands):

Purchased Power in the table above includes about $10.4 million in 2003 and $10.9 million in 2002 related to the purchase of power from the Company, under Connecticut Valley's long-term contract with the Company. These amounts are included in Operating Revenue on the Consolidated Statements of Income. Accounts Receivable from Connecticut Valley were of a nominal amount in 2004 and $1.8 million in 2003.

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The major classes of assets and liabilities reported as discontinued operations on the Consolidated Balance Sheets are as follows (in thousands):

LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2004, we had cash and cash equivalents of $11.7 million and working capital of $67.7 million. During 2004, cash and cash equivalents decreased by $12.1 million. The decrease resulted from the following: 1) $52.1 million used by investing activities mostly for Catamount investments, construction expenditures, investment in VELCO and investments in available-for-sale securities as described below, partly offset by sales of projects from Catamount's portfolio; 2) $15.7 million used in financing activities primarily related to dividends paid on common and preferred stock and retirement of long-term debt and preferred stock; 3) $25.6 million provided by operating activities; and 4) $30.1 million provided by discontinued operations.

At December 31, 2003, we had cash and cash equivalents of $23.8 million and working capital of $68.6 million. During 2003, cash and cash equivalents decreased $16.9 million. The decrease resulted from the following: 1) $35.1 million used by investing activities for available-for-sale securities, construction expenditures, partially offset by the Vermont Yankee sale proceeds received in 2003; 2) $27.3 million used in financing activities mostly related to retirement of long-term debt and dividends paid on common and preferred stock and $10.6 million for restricted cash used to reduce non-utility long-term debt and redeemable preferred stock; and 3) $46.6 million provided by operating activities.

In the first quarter of 2004, we invested proceeds received from the Connecticut Valley sale and other cash on hand in available-for-sale securities with various maturities. At December 31, 2004, these investments included $19.3 million with maturities from 90 days up to one year and $21.9 million with maturities greater than one year.

We are considering investment alternatives and plan to continue investing additional funds in Vermont Electric Power Corporation, Inc.'s ("VELCO") planned transmission upgrades. Our investments in VELCO will contribute toward increasing VELCO's common equity from about 10 percent to 25 percent of its total capitalization. On August 17, 2004, FERC approved our joint filing with Green Mountain Power Corporation ("GMP") for authorization to purchase stock to be issued by VELCO in 2004 and 2005 in connection with financing its planned transmission upgrades. We invested about $7 million in December 2004 and intend to invest about $5.7 million in the latter part of 2005. VELCO will require additional equity capital beyond 2005 in order to finance all of the proposed transmission upgrades and we will consider additional investments in VELCO. In total, our investments in VELCO, including our December 2004 investment, could amount to about $30 million to $35 million through 2007.

Catamount has sufficient cash flow to cover its ongoing operating expenses, but additional project investments will require financing or additional funding from us. Catamount is also seeking investors and partners to co-invest in the development, ownership and acquisition of projects.

We believe that cash on hand and cash flow from operations will be sufficient to fund our business for the foreseeable future, although without a rate increase, Vermont utility cash flow from operations will decrease in 2005 when compared to 2004. Material risks to cash flow from operations include: adverse rate case outcome; 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.

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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 capital expenditure plan is expected to range from $60 million to $70 million for the three-year period between 2005 and 2007. Our significant contractual obligations as of December 31, 2004 are summarized in the table below.

Pension and Postretirement Benefits
See Note 10 to the Consolidated Financial Statements for expected cash flows related to Pension and Postretirement Benefits.

Financing
Utility On July 30, 2004, we issued $20 million of 5 percent First Mortgage Bonds, due in 2011, and $55 million of 5.72 percent First Mortgage Bonds, due in 2019. The proceeds were used to repay in full our $75 million Second Mortgage Bonds, at a rate of 8.125 percent that matured on August 1, 2004. The refinancing and lower interest rates will reduce annual interest expense by about $2 million on a pre-tax basis.

The First Mortgage Bonds are callable at our option at any time upon payment of a make-whole premium, calculated as the excess of the present value of the remaining scheduled payments to bondholders, discounted at a rate that is 0.5 percent higher than the comparable U.S. Treasury Bond yield, over the early redemption amount.

Currently, the Vermont Industrial Development Authority Bonds and the Connecticut Development Authority Bonds are callable at par at the option of the Company or bondholders on each monthly interest payment date, or at the option of the bondholders on any business day. We have always been able to remarket any bonds submitted for prepayment by the bondholders. The New Hampshire Industrial Development Authority Bonds are no longer callable at our option or at the bondholders' option, except in special circumstances involving unenforceability of the indenture or a change in the usability of the project.

None of our debt financing documents contain cross-default provisions to affiliates outside of the consolidated entity. Certain of our debt financing documents contain cross-default provisions to our wholly owned subsidiaries, East Barnet, CV Realty and Custom Investment Corporation. These cross-default provisions generally relate to an inability to pay debts or debt acceleration, inappropriate affiliate transactions or the levy of significant judgments or attachments against our property. Currently, we are not in default under any of our debt financing documents.

Based on outstanding debt at December 31, 2004, no principal payments are due on long-term debt from 2005 through 2007. At December 31, 2004, substantially all utility property and plant were subject to liens under the First Mortgage Bond indenture. Also, the First Mortgage Bond indenture restricts financial support to Catamount and other unregulated subsidiaries at $17.5 million plus 20 percent of annual net income starting January 2004 and prevents any guarantee of Catamount's or other unregulated subsidiaries' obligations. In return, the First Mortgage Bond indenture eliminates the risk of cross default by Catamount and other unregulated subsidiaries.

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At December 31, 2004, we were in compliance with all debt covenants related to our various debt agreements, Articles of Association and letters of credit; these agreements contain financial and non-financial covenants.

Dividend restrictions: The First Mortgage Bond indenture and the Company's Articles of Association contain certain restrictions on the payment of cash dividends on capital stock. Under the most restrictive of such provisions, approximately $99 million of retained earnings was not subject to dividend restriction at December 31, 2004.

Non-Utility In January 2004, Catamount paid off a $2.5 million balance on its term loan, and in February 2004, Catamount notified the lender of its intent to terminate the credit facility. Effective May 16, 2004, the credit facility was officially terminated. Catamount's office building mortgage matured on April 15, 2004, and Catamount paid the outstanding balance in full.

Catamount solicits, as needed, 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 enter into an appropriately priced corporate and/or development credit facility.

As part of its windfarm development efforts, in August 2004, Catamount entered into a construction lending arrangement for about $27.3 million for a wind project located in the United States. At December 31, 2004, Catamount advanced $22.6 million for construction of the project. On February 11, 2005, the construction loan was paid off and Catamount made an equity investment in the wind project, referred to as Sweetwater 2.

In November 2004, Catamount entered into an agreement with a third-party developer for the purchase of wind turbines for a joint development project. Pursuant to the agreement, Catamount made a total of $5.9 million of payments to the turbine supplier in the fourth quarter of 2004. The turbine supply agreement calls for payments of $5.9 million in March 2005 and $14.8 million in September 2005, with the remaining contract amount of $32.5 million due based on milestones established in the agreement. Catamount expects third-party construction financing, for the wind project that the turbine agreement is associated with, to be in place in the second quarter of 2005. Once the construction financing is in place, Catamount would be relieved of making the September 2005 and remaining payments to the turbine supplier. The turbine supply agreement allows for termination in full up to 30 days prior to the delivery of the first turbines. After that date, Catamount can terminate future turbines (partial terminati on) 30 days prior to scheduled delivery. In the event of a termination of the turbine supply agreement in whole or in part for the joint development project, the third-party developer or Catamount has up to 18 months from the termination date to utilize the turbines and receive reimbursement of 85 percent of the turbine down-payments.

Letters of Credit: We renewed $16.9 million of unsecured letters of credit issued by a financial institution to November 30, 2005. These letters of credit support three series of Industrial Development Revenue Bonds, totaling $16.3 million. At December 31, 2004 and 2003, there were no amounts outstanding under these letters of credit.

Operating Leases: We lease our vehicles and related equipment under one operating lease agreement. The leases are mutually cancelable one year from each individual lease inception. We have the ability to lease vehicles and related equipment up to an aggregate unamortized balance of $10 million, of which about $4.4 million was outstanding for the years ended 2004 and 2003.

Under the terms of the vehicle operating lease, we have guaranteed a residual value to the lessor in the event the leased items are sold. The guarantee provides for reimbursement of up to 87 percent of the unamortized value of the lease portfolio. Under the guarantee, if the entire lease portfolio had a fair value of zero at December 31, 2004, we would have been responsible for a maximum reimbursement of $3.9 million and at December 31, 2003, we would have been responsible for a maximum reimbursement of $3.8 million. We had a liability of $0.1 million at December 31, 2004 representing our obligation under the guarantee based on the fair market value of the entire portfolio.

Other operating lease commitments are considered minimal, as most are cancelable after one year from inception. Total rental expense, including the operating lease agreement described above, included in the determination of net income, amounted to about $5.2 million in 2004, $4.4 million in 2003 and $4.5 million in 2002.

Power Supply Commitments: We have material power supply commitments that are discussed in detail in Note 13 - Commitments and Contingencies.

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Equity Investments: We own an equity interest in VELCO in which we are required to pay a portion of VELCO's operating costs based on our network load percentage and to contribute additional capital if VELCO's transmission rates do not provide for full cost recovery. We own an equity interest in VYNPC in which we are obligated to pay a portion of VYNPC's operating costs based on our entitlement percentage. See Note 2 - Investments in Affiliates for additional information related to these equity investments.

Other: We do not use off-balance sheet financing arrangements, such as securitization of receivables, or obtain access to assets through special purpose entities.

Credit Ratings

On November 16, 2004, 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 average business profile and a somewhat below-average financial profile. Our financial profile is pressured by adjustments made by S&P related to some of our long-term purchased power contracts. Our business profile is characterized by a diverse customer mix, stable demand growth and low operating risk. These strengths are offset by significant regulatory uncertainty and our continued commitment to non-regulated businesses, including wind-power projects in the United States and United Kingdom. S&P's stable outlook was based upon expectations that our regulatory environment will not deteriorate and that future financial support of unregulated businesses will be measured.

On December 14, 2004, Fitch Ratings ("Fitch") upgraded our preferred stock rating to 'BBB-' from 'BB+'. Fitch also affirmed our first mortgage bond rating at 'BBB+' 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.

Our credit is currently investment grade. Credit ratings should not be considered a recommendation to purchase stock. Current credit ratings are as follows:

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.

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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 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. 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 standard 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 $38.9 million on a pre-tax basis as of December 31, 2004, 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 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 $0.2 million in 2004, $1.3 million in 2003 and $1.4 million in 2002, 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 repo rted 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 determining viability of 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 fair value, based on undiscounted cash flows, 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 2004, Catamount determined that its investments in wind projects in Germany were impaired by about $0.2 million based on their current market value, and its Appomattox investment was impaired by about $0.1 million. In 2003, Catamount determined that its investments in Rupert and Glenns Ferry were impaired by amounts that were not significant, and in 2002, Catamount recorded after-tax asset impairment charges of $2.1 million related to certain of its investments. These asset impairments were based on underlying purchase and sale contracts. 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, we make various estimates including: 1) energy generated, purchased and resold; 2) losses of energy over transmission and distribution lines; 3) kilowatt-hour usage by retail customer mix - residential, commercial and industrial; and 4) average retail customer pricing rates. We use these estimated amounts to calculate the amount of revenue that has been earned, but not billed, due to the timing of billing cycles used for retail customers.

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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 management determines it is more likely than not such tax assets will not be realized. See Income Tax Issues below for additional information.

Reserve for Loss on Power Contract In accordance with the requirements of SFAS No. 5, we recorded a $14.4 million pre-tax loss accrual related to termination of our long-term power contract with Connecticut Valley in 2004. The contract was terminated as a condition of the Connecticut Valley sale. The loss accrual represented Management's best estimate of the difference between expected future sales revenue, in the wholesale market, for the purchased power that was formerly sold to Connecticut Valley and the cost of purchased power obligations. The estimated life of the power contracts that were in place to supply power to Connecticut Valley extends through 2015.

The loss accrual was estimated based on assumptions about future power prices, the reallocation of power from the state-appointed purchasing agent ("VEPPI") and future load growth. Management will continue to review this estimate at the end of each reporting period and will increase the reserve if the revised estimate exceeds the recorded loss accrual. Additionally, the loss accrual is being amortized on a straight-line basis, as required by GAAP, through 2015. In 2004, we recorded $1.2 million of amortization. The loss accrual and amortization are included in Purchased Power on the Consolidated Statement of Income in the amount of $13.2 million for the period ended December 31, 2004.

Derivative Financial Instruments We account for various power contracts as derivatives under the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted. In April 2003, the Financial Accounting Standards Board ("FASB") issued SFAS No. 149, Amendment of Statement 133 Derivative Instruments and Hedging Activities, effective for contracts entered into or modified after June 30, 2003, which amends and clarifies accounting for derivative instruments (collectively "SFAS No. 133"). These statements require that derivatives be recorded on the Consolidated Balance Sheets at fair value. Adoption and application of these statements did not impact our results of operation. At December 31, 2004, we had two power contract derivatives; one valued at quoted market prices and one based on modeling techniques, as described below.

Our long-term contracts for the purchase of power from VYNPC and Independent Power Producers do not meet the definition of a derivative under the requirements of SFAS No. 133 because delivery of power under these contracts is contingent on plant output. Additionally, our long-term power contract with Hydro-Quebec does not meet the definition of a derivative because there is no defined notional amount. See discussion of Power Supply Matters below for additional information related to these contracts.

We have a long-term purchased power contract that allows the seller to repurchase specified amounts of power with advance notice (Hydro-Quebec Sellback #3). This contract has been determined to be a derivative and is being accounted for under SFAS No. 133.  The derivative's year-end estimated fair value was an unrealized loss of $5.7 million in 2004 and an unrealized loss of $1.2 million in 2003. The change in value for 2004 versus 2003 reflects higher forecasted market prices during the contract term. The estimated fair value of this derivative is valued using a binomial tree model, and quoted market data when available along with appropriate valuation methodologies.

In November 2004, we entered into two forward sale contracts, one through October 2006 and one through December 2008. The sole purpose of entering into these contracts is to manage price risk from power supply resources used to serve our customers. We enter into forward sale contracts when we forecast excess supply, and to minimize the net costs and risk of serving our customers. Both of these forward sale contracts require the physical delivery of power, but one is contingent upon Vermont Yankee plant output. We have assessed these two contracts and determined that one is a derivative under SFAS No. 133, and the other, due to the unit contingent nature of the contract, is not a derivative. The derivative contract is for delivery of about 15 MW per hour, or a total of 522,544 mWh for the contract term, which extends from November 17, 2004 through December 31, 2008. At December 31, 2004, this contract had an estimated fair value of a $0.4 million unrealized gain. We used over-the-counter quotations or broker quotes at December 31, 2004 to determine the fair value of this contract.

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In December 2003, we entered into a forward sale contract for about 148,400 mWh for the period beginning January 1 and ending March 31, 2004, and a forward purchase contract for about 27,100 mWh for the month of April 2004. We entered into these contracts to minimize the net costs and risks of serving customers, including replacement power related to the Vermont Yankee plant's April 2004 scheduled refueling outage. We determined that both contracts did not meet the normal purchase and sale exclusion under SFAS No. 133. At December 31, 2003, the forward sale contract had an estimated fair value of a $0.4 million unrealized gain, and the forward purchase contract had an estimated fair value of a $0.1 million unrealized loss. We used over-the-counter quotations or broker quotes at December 31, 2003 to determine the fair value of these contracts. These derivative contracts were settled by December 31, 2004, and are included in Operating Revenue or Purchased Power on the Consolidated Statement of Income f or 2004.

We record derivative contracts on the Consolidated Balance Sheets at fair value. Based on a PSB approved Accounting Order, the changes in fair value are recorded as deferred charges or deferred credits on the Consolidated Balance Sheets depending on whether the fair value is an unrealized loss or gain.

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, 2004, based on the most recent estimates provided, our share of remaining costs to decommission these nuclear units is about $5.8 million for Maine Yankee, $12.6 million for Connecticut Yankee and $4.2 million for Yankee Atomic. These estimates are recorded in the accompanying Consolidated Balance Sheet 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, and we have an external trust to fund our share of decommissioning costs. Contributions to the 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 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, which is being addressed in our current 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. 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 assumptions 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. The selection methodology used in determining the discount rate includes portfolios of "Aa" bonds; all are United States issues and non-callable (or callable with make-whole features) and each issue is at least $50 million. As of September 30, 2004, the discount rate remained at 6 percent.

• Expected Return on Plan Assets ("ROA") - We project the future ROA based principally on historical returns by asset category and expectations for future returns, based 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, 2003, the ROA was 8.25 percent. This rate was used to determine the annual expense for 2004 and the same rate will be used to determine the 2005 expense.

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• Rate of Compensation Increase - We project employees' annual pay increases, which are used to project employees' pension benefits at retirement. As of September 30, 2004, the rate of compensation increase remained at 3.75 percent.

• Health Care Cost Trend - We project expected increases in the cost of health care. For measurement purposes, we assumed an 11 percent annual rate of increase in the per capita cost of covered health care benefits for pre-65 claims, and a 10.5 percent increase for post-65 claims, for fiscal 2005. 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.

Pension costs and cash funding requirements are expected to increase in future years. As of December 31, 2004, the market value of pension plan trust assets was $64.2 million, including $44.3 million in marketable equity securities and $19.9 million in debt securities. Pension plan trust assets were $61.3 million at December 31, 2003, including $42.5 million in marketable equity securities and $18.8 million in debt securities.

Favorable market returns of about $6.6 million in 2004 and about $12.1 million in 2003 helped to offset the adverse effect of sharp declines in the capital markets in 2001 and 2002. Annual pension cost increased by $0.7 million in 2004. Of that amount, $0.6 million is reflected in results of operations and the remaining amount is capitalized.

Postretirement costs also increased by $0.8 million for 2004 due to higher-than-expected medical claims experience. Of that amount, $0.7 million is reflected in results of operations and the remaining amount was capitalized.

Pension and Postretirement Assumption Sensitivity Analysis Fluctuations in market returns may result in increased or decreased pension costs in future periods. The table below shows how a 25-basis-point change in discount rate and expected return on assets would affect pension costs. Any additional decreases in the discount rate would increase the charge to equity by the same amount as the Accumulated Benefit Obligation (ABO).

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

RESULTS OF OPERATIONS
The following is a detailed discussion of the Company's results of operations for the past three years. This should be read in conjunction with the consolidated financial statements and accompanying notes included in this report.

Consolidated Summary: Consolidated 2004 earnings were $23.8 million, or $1.93 per basic and $1.90 per diluted share of common stock. Consolidated 2003 earnings were $19.8 million, or $1.57 per basic and $1.53 per diluted share of common stock, while consolidated 2002 earnings were $19.8 million, or $1.56 per basic and $1.53 per diluted share of common stock.

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In 2004 discontinued operations of Connecticut Valley contributed $12.3 million, or $1.02 per basic and $1.00 per diluted share of common stock, to consolidated earnings. This reflects a $12.3 million after-tax gain on disposal of discontinued operations related to the January 1, 2004 sale of Connecticut Valley's plant assets and franchise. In 2003, discontinued operations of Connecticut Valley contributed $1.4 million, or $.12 per basic and diluted share of common stock, to consolidated earnings, and it contributed $1.5 million, or $.13 per basic and diluted share of common stock, in 2002.

For accounting purposes, components of the Connecticut Valley transaction in 2004 are recorded in both continuing and discontinued operations in the Consolidated Statement of Income. The gain on the asset sale, net of tax, totaled $12.3 million, but we recorded a loss on power costs, net of tax, of $8.4 million relating to termination of the power contract between us and Connecticut Valley. The loss is recorded as Purchased Power in the Consolidated Statement of Income. When the two accounting transactions are combined to assess the total impact of the transaction, the result is a gain of $3.9 million, or $.31 per diluted share of common stock.

The following table provides a reconciliation of 2004 and 2003 diluted earnings per share.

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

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(1) Based on FERC filed tariffs

The average number of retail customers is summarized below:

Comparative changes in Operating revenues are summarized below:

• Retail and firm sales increased $3.8 million primarily due to higher sales volume. These sales are affected by weather and economic conditions. Lower average industrial prices due to higher usage per customer partially offset the favorable effect of higher sales volume.
• The January 1, 2004 termination of the power contract with Connecticut Valley decreased resale revenue by $10.4 million, but made about 123,000 mWh available for use by the Company or for other resale sales. The effects of the contract termination are reflected as higher resale revenue or lower short-term purchases.

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• Other resale revenue increased $1.9 million due to higher average market prices, partly offset by lower sales volume. The lower volume resulted from fewer mWh available for resale due to scheduled nuclear plant outages at Vermont Yankee and Millstone Unit #3 in the second quarter of 2004, and a 19-day unscheduled outage at the Vermont Yankee plant that ended July 7, 2004. The lower volume was partially offset by termination of the Connecticut Valley power contract.
• Other operating revenue increased $0.9 million primarily due to service billings related to mutual aid work in Florida. Revenue related to fees charged for use of utility poles, referred to as pole attachments, increased as a result of a field inventory completed in 2003, and transmission revenue also increased slightly.

2003 vs. 2002

Operating revenues increased $11.6 million, or 4 percent, in 2003 compared to 2002 due to the following factors:

• Retail and firm sales increased $3.2 million primarily due to a 1 percent 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.
• 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.
• 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 higher contract rates were related to a forward sale in 2003 in which we sold about 306,000 mWh during the period February through December 2003. In 2002 most of our resale sales were made at ISO-New England market prices. We had more mWh available for resale primarily due to increased output from Vermont Yankee and Millstone, as neither plant was off-line for scheduled refueling and maintenance in 2003. Also, Vermont Yankee had a second quarter 2002 unscheduled outage for fuel rod repairs.
• Other operating revenue increased about $0.1 million.

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The related mWh purchases and unit price from these sources are summarized below:

• In the first quarter of 2004, in accordance with SFAS No. 5, we recorded a $14.4 million pre-tax loss accrual related to termination of the power contract with Connecticut Valley. The loss accrual represents Management's best estimate of the difference between expected future sales revenue, in the wholesale market, for the purchased power that was formerly sold to Connecticut Valley and the cost of purchased power to be incurred to realize those future sales. In accordance with GAAP, the loss accrual is being amortized on a straight-line basis through 2015, which represents the estimated life of our power contracts that were in place to source the Connecticut Valley power contract. In 2004, amortizations reduced purchased power expense by $1.2 million, for a net impact of $13.2 million.
• Short-term purchases, which include purchases from ISO-New England and third parties in New England, increased $6.6 million primarily due to replacement energy for the Millstone Unit #3 refueling outage and the Vermont Yankee outages. We deferred about $1.2 million for incremental replacement energy costs related to the Millstone Unit #3 refueling outage and Vermont Yankee unscheduled outage, compared to $0.4 million of amortizations of replacement energy deferrals related to a Millstone Unit #3 2002 refueling outage. These deferrals and amortizations are included in Accounting (deferrals) amortizations in the table above.
• IPP purchases increased $1.2 million, primarily due to higher output from these facilities and higher rates. The majority of IPPs are hydro facilities and output is based on weather conditions that affect water flow.
• Nuclear decommissioning costs are related to our share of Maine Yankee, Connecticut Yankee and Yankee Atomic decommissioning costs. Our share of decommissioning costs increased $0.2 million, due to changes in FERC-approved rates in 2004. The amounts in the table above are reflected net of accounting deferrals, which are described in more detail in Power Supply Matters - Nuclear Generating Companies below.
• Vermont Yankee purchases decreased $7.9 million, excluding a 2003 refund. About $6.9 million of the decrease is primarily due to a scheduled refueling outage and a 19-day unscheduled outage in 2004 versus no plant outages in 2003. Also in 2003, Vermont Yankee received a refund related to defective fuel rods that caused an unscheduled outage in 2002. For accounting purposes our share of the refund, about $1 million, was used to decrease deferred charges related to incremental replacement energy costs resulting from the outage. The refund is included in Vermont Yankee purchases, while the offset is included in Accounting (deferrals) amortizations in the table above.
• Hydro-Quebec purchases decreased $0.6 million due to fewer deliveries under the Hydro-Quebec contract resulting from interconnection deficiencies.

Purchased power expense increased $10.6 million, or 7.4 percent, in 2003 compared to 2002 as a result of the following factors:

• An $11.6 million increase in Vermont Yankee-related costs primarily resulting from higher plant output in 2003, which increased purchases by about $8.2 million. Other factors that resulted in a net $3.4 million increase when comparing 2003 versus 2002 included 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 and $5.2 million of sale-related deferrals in 2002, offset by about $4 million due to elimination of amortizations for Vermont Yankee nuclear refueling outages.
• A $1 million increase in purchases from IPPs due to higher volume and rates.
• A $1.7 million decrease in purchases from Hydro-Quebec due to reduced deliveries resulting from interconnection deficiencies.
• A $0.4 million decrease in short-term purchases, including the impacts of accounting deferrals and amortizations of replacement energy costs in 2003 and 2002. The variance when comparing 2003 versus 2002 is attributed to the following factors: 1) 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, with no comparable credits in 2003; 2) a $1.3 million decrease in short-term and spot energy purchases; 3) a $1 million decrease in installed capacity purchases due to lower rate and volume; and 4) a $0.1 million decrease in other costs.

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Production and transmission: These expenses are primarily associated with generating electricity from our wholly and jointly owned units, and transmission of electricity. The $0.6 million decrease in 2004 is primarily due to lower output from jointly owned units and lower transmission costs.

Other operation: These expenses are primarily related to operating activity such as customer accounting, customer service, administrative and general and other operating costs incurred to support our core business. The $4 million increase includes about $1.3 million related to reducing the Vermont utility's earnings to achieve an 11 percent return on equity. In 2004, based on a PSB-approved Accounting Order, this amounted to a $3.8 million pre-tax expense. In 2003, per the July 2001 PSB-approved rate order, this amounted to a $2.5 million pre-tax expense. In both years, we recorded related regulatory liabilities for these amounts. See Vermont Retail Rates discussion above for additional information.

The remaining $2.7 million increase resulted from higher employee-related costs (pension and medical), higher pole attachment expenses that are offset in Operating Revenue above, higher professional services costs related to Sarbanes-Oxley project readiness, the rate case and general legal expenses, and higher bad debt expense related to a second quarter 2004 customer bankruptcy. These increased costs are partially offset by the favorable impact of an insurance settlement received in the second quarter of 2004 and the favorable impact of conservation and load management amortizations that ended in 2003.

The $3.3 million increase for 2003 versus 2002 is primarily related to the Vermont utility's mandated earnings cap, which resulted in a pre-tax expense of $2.5 million in 2003 to achieve the mandated earnings cap. 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: These expenses are primarily related to costs associated with maintaining our electric distribution system. There was no significant variance for 2004 versus 2003 or for 2003 versus 2002.

Depreciation: We use the straight-line remaining-life method of depreciation. There was no significant variance for 2004 versus 2003 or for 2003 versus 2002.

Other taxes, principally property taxes: This is primarily related to property taxes and payroll taxes. There was no significant variance for 2004 versus 2003 or for 2003 versus 2002.

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. The effective tax rate was 3.1 percent for 2004, 32 percent for 2003 and 37.8 percent for 2002. The effective tax rate decreased significantly in 2004 primarily due to tax benefits associated with the sale of certain of Catamount's equity investments in 2004. The effective tax rate for 2003 decreased when compared to 2002 primarily due to a decrease in the valuation allowance. See Income Tax Matters below and Note 11 to the Consolidated Financial Statements for additional information related to Income Taxes.

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During 2004, we received three income tax refunds totaling $0.9 million (exclusive of interest). One refund related to an appeal of an overpayment from a prior federal income tax audit for the tax years 1982 through 1984. The proceeds from the settlement included a federal income tax refund of $0.5 million. The other two refunds related to an appeal of federal and state income tax overpayments for 2000. The proceeds from the settlements included a federal income tax refund of $0.3 million and a state refund of $0.1 million. We also decreased the estimate for tax contingencies by $0.3 million due to a reduction in potential tax liabilities.

On June 7, 2004, the State of Vermont enacted legislation that reduced the state income tax rate from 9.75 percent to 8.9 percent effective January 1, 2006, and from 8.9 percent to 8.5 percent effective January 1, 2007. Deferred tax assets and liabilities were adjusted in 2004 to reflect the enacted income tax rate change. This rate change reduced regulatory tax assets by about $1.4 million, and increased income tax expense by about $0.2 million. The decrease in regulatory assets was primarily caused by a decrease in operating deferred tax liabilities. The increase in tax expense was primarily caused by a reduction in non-operating deferred tax assets.

Equity in earnings of affiliates: These are related to our equity investments, primarily VELCO and VYNPC. The $0.6 million decrease is primarily related to lower VYNPC interest income. VYNPC's interest income was higher in 2003 due to sale proceeds that were not disbursed until October 2003. The $2.1 million decrease for 2003 versus 2002 was 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. The July 2002 sale of the Vermont Yankee plant has reduced our ongoing equity in earnings from that investment.

Equity in earnings of non-utility investments: These are related to Catamount's equity investments in non-regulated independent power projects. The $2.1 million decrease is primarily due to lower earnings from its investments in Glenns Ferry, Rupert, Rumford and Catamount Energy Limited. The $5.3 million decrease for 2003 versus 2002 was primarily due to the October 2002 sale of its Heartlands investments, lower earnings from its Rumford investment due to an accelerated depreciation adjustment and lower earnings from its investments in Appomattox and Ryegate. See Diversification below.

Gain on sale of non-utility investments:  In 2004, Catamount completed the sale of its Glenns Ferry and Rupert investments and the sale of its Fibrothetford note receivable and equity investment. These asset sales amounted to a pre-tax gain of about $2.5 million in 2004. There were no asset sales in 2003, and in 2002 asset sales approximated book value, therefore there were no associated gains or losses. See Diversification below.

Allowance for equity funds used during construction: This is the cost of equity financing during construction projects. It is capitalized as part of major utility plant projects when costs applicable to such construction work in progress have not been included in rate base through ratemaking proceedings.

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Other income: These income items include interest and dividend income, interest on temporary investments and non-utility notes receivable, Catamount's operating revenue, regulatory asset carrying costs, amortization of contributions in aid of construction and various miscellaneous other income items.

The $1.6 million increase is primarily due to higher interest income on temporary investments and available-for-sale securities, resulting from investment of cash proceeds from the Connecticut Valley sale and other cash on hand in early 2004. Other factors include higher interest and dividend income primarily related to interest received as part of an IRS tax settlement and higher non-utility revenue due to fees associated with Catamount's United Kingdom development efforts, offset by lower miscellaneous other income.

The $0.4 million increase for 2003 versus 2002 is primarily related to higher interest on non-utility notes receivable, higher non-operating rental income, higher regulatory asset carrying costs and higher miscellaneous other income, offset by lower non-utility revenue due to realized development revenue in 2002 upon the sale of one of Catamount's investments.

Other Deductions: These deductions include Catamount's operating expenses, asset impairment charges, supplemental retirement benefits and insurance, including changes in the cash surrender value of life insurance policies, and miscellaneous other deductions.

The $1.6 million decrease in 2004 is primarily related to lower Catamount operating expenses due to lower business development and other consulting expenses. Business development expenses were lower as a result of entering into development arrangements with third parties in 2004. Other consulting expenses were lower primarily due to the expensing in 2003 of previously capitalized costs related to the private equity placement efforts.

The $6 million decrease for 2003 versus 2002 was primarily related to lower life insurance expense resulting from a significant increase in the cash surrender value of certain life insurance policies due to financial market results, and various one-time items in 2002, which result in a favorable variance when comparing 2003 versus 2002. These one-time items included $2.7 million pre-tax asset impairment charges in 2002 related to Catamount's investments that were sold in the fourth quarter of 2002, a one-time payment of $1 million to the non-Vermont owners related to closing the Vermont Yankee sale, and lower Eversant operating expense due to discontinuance of its efforts to pursue unregulated business opportunities.

Benefit (provision) for income taxes:  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. The increase for 2004 is primarily due to higher Catamount earnings related to the sales of investment interests. In the third quarter of 2003 there was also a $2.3 million reduction in income tax valuation allowances associated with previously recorded equity losses from asset impairments. In 2003, the consolidated federal income tax provision reflected a benefit due to realization of capital gains on the Connecticut Valley sale, which afforded Catamount the opportunity to reduce tax valuation allowances. Also see Income Tax Matters below.

Interest on long-term debt: The $2.3 million decrease in 2004 includes $1.3 million resulting from lower long-term debt and $1 million resulting from lower interest rates due to the August 2004 bond refinancing. The $1.3 million decrease for 2003 versus 2002 is primarily related to lower long-term debt. See Financing above for additional information.

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Other interest expense: The $0.4 million increase is primarily related to the reclassification of dividends on mandatorily redeemable preferred stock to interest expense as described in Dividends on preferred stock below, and increased carrying costs on regulatory liabilities. This was partially offset by the IRS tax settlement described above. The $0.6 million decrease for 2003 versus 2002 is primarily related to Eversant's 2002 settlement of an IRS audit resulting in the reversal of a related interest expense accrual previously recorded in the fourth quarter of 2001.

Allowance for borrowed funds during construction: This is the cost of debt financing during construction projects that we capitalize as part of the cost of major utility plant projects when costs applicable to such construction work in progress have not been included in rate base through the ratemaking process. There was no significant variance in these expenses for 2004 versus 2003 or 2003 versus 2002.

Sources of Energy Our power supply portfolio includes a mix of base load, dispatchable and energy-constrained schedulable resources. A breakdown of energy sources is shown below:

Our joint-ownership interests include 1.73 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. Combined, these contracts contributed about 84 percent of our total energy (mWh) purchases in 2004, compared to 90 percent in 2003 and 87 percent in 2002. We are also required to purchase power from various Independent Power Producers ("IPPs") under long-term contracts. These contracts are discussed in more detail below.

Power Contract Commitments
Hydro-Quebec We purchase varying amounts of power from Hydro-Quebec under the Vermont Joint Owners ("VJO") Power Contract and related contracts negotiated between us and Hydro-Quebec that altered the terms and conditions of the original contract by reducing the overall power requirements and related costs. Our purchases under these contracts extend through 2016. 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, 2004, our obligation is about 46 percent of the total VJO Power Contract, which translates to about $663 million, on a nominal basis, over the contract term. See Note 13 to the Consolidated Financial Statements for further discussion of this contract.

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In January 2004, Hydro-Quebec notified the VJO that, due to interconnection deficiencies, it would not be able to reschedule energy not delivered during the 2002 - 2003 and 2003 - 2004 contract years. We continue to work with Hydro-Quebec to minimize future interconnection deficiencies through various scheduling modifications and use of interconnection facilities. Our estimated cost of energy and capacity under the existing contracts with Hydro-Quebec are $58.5 million in 2005, $62.1 million in 2006, $62.3 million in 2007, $63.1 million in 2008 and $64 million in 2009.

VYNPC We have a 35 percent entitlement in Vermont Yankee plant output sold by Entergy ("ENVY") to VYNPC, through a long-term power purchase contract with VYNPC. 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 VYNPC and the entitlement holders and between VYNPC and ENVY became effective on July 31, 2002, the same day that the Vermont Yankee nuclear plant was sold to ENVY. 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. ENVY has no obligation to supply energy to VYNPC over the amount the plant is producing, so entitlement holders receive reduced amounts when the plant is operating at a reduced level, and no energy when the plant is not operating.

The PPA through which VYNPC purchases power from ENVY and in turn sells to its sponsors includes prices that range from 3.9 cents to 4.5 cents per kilowatt-hour through March 2012. Effective November 2005, the contract prices are subject to a "low-market adjuster" that protects us 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 12-month average (ending in same billing month) of hourly market prices as defined in the PPA. If the 12-month average market price is less than 95 percent of the base PPA contract price, then 105 percent of the 12-month average market price will be used for the billing month. The low-market adjusted price cannot exceed the base PPA contract price. If the market prices rise, however, contract prices are not adjusted upward. In addition to PPA charges, VYNPC's billings to the sponsors include certain of its residual costs of service through a FERC tariff to the VYNPC 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.

Purchases from VYNPC amounted to about $58.3 million in 2004, $65.2 million in 2003 and $60.2 million in 2002, and are included in Purchased Power on the Consolidated Statements of Income. Accounts Payable to VYNPC amounted to $5.8 million at December 31, 2004 and $4.6 million at December 31, 2003. Future VYNPC purchases are expected to be $57.1 million in 2005, $61.1 million in 2006, $58.0 million in 2007, $59.7 million in 2008 and $65.8 million in 2009.

In 2003, ENVY sought PSB approval to increase generation at the Vermont Yankee plant by 110 megawatts. Our purchases from VYNPC will not be affected by increased generation but our entitlement percentage of plant output will decrease about 29 percent. On March 15, 2004, the PSB approved the proposal, but its approval was conditioned on ENVY providing an outage protection indemnification ("Ratepayer Protection Proposal" or "RPP") for us and GMP in case the uprate causes temporary reductions in output that reduce our value of the PPA. Our maximum right to indemnification under the RPP is about $2.8 million, and will be in place for three years to cover any uprate-related reductions in output.

Plant output has been reduced since the April 2004 scheduled refueling outage, and will continue until ENVY receives NRC approval for the uprate. Our 182 MW entitlement was reduced by an average of about 4 MW during this period. The financial effect of such a reduction will be covered under the terms of the RPP. In 2004, ENVY made a payment of an undisputed amount under the RPP and we are seeking agreement with ENVY on a final payment.

On June 18, 2004, an incident that caused a fire at the Vermont Yankee plant's transformer caused the plant to shut down for about 19 days. We deferred about $0.8 million of incremental replacement energy costs incurred as a result of the outage, per the PSB's preliminary approval of our request for an Accounting Order. The Final Accounting Order is being addressed as part of our rate case. We believe the plant went off line due to problems associated with uprate-related improvements made by ENVY, and have sought about $0.8 million from ENVY to cover the incremental replacement energy costs resulting from the outage. ENVY contends that the problem would have occurred regardless of the uprate. We engaged in discussions with ENVY relating to settlement of this dispute in accordance with the RPP. Having failed to reach a settlement with ENVY, we petitioned the PSB for resolution. On February 18, 2005, the PSB held a prehearing conference and set a schedule that provides for resolution in the third qua rter of 2005. We and ENVY agreed to remain in settlement discussions relating to this matter.

In April 2004, in response to an NRC inspection conducted during the Vermont Yankee plant's scheduled refueling outage, ENVY reported that two short spent fuel rod segments were not in what ENVY believed to be their documented location in the spent fuel pool. According to ENVY, in 1979 the rods were placed in a special stainless steel container in the spent fuel

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pool. After initial document review and visual inspection of the spent fuel pool, ENVY did not locate the fuel rod segments. On May 5, 2004, ENVY notified VYNPC that based on the terms of the Purchase and Sale Agreement dated August 1, 2001, and facts at the time, it was their view that costs associated with the spent fuel rod segment inspection effort were the responsibility of VYNPC. On May 20, 2004, VYNPC responded that based on the information at the time there was no basis for ENVY's claim. Subsequently, ENVY's continuing documentation review led to the discovery of the fuel rod segments in a container in the spent fuel pool. The NRC has begun its own investigation into ENVY's accounting for these segments. We cannot predict the outcome of this matter at this time.

Nuclear industry practice typically is to maintain the capacity to off-load the entire active nuclear fuel core into the spent fuel pool as a safety measure; this is called maintaining full core discharge capability. ENVY anticipated that to maintain full core discharge capability, dry cask storage of spent nuclear fuel will be needed at the Vermont Yankee plant by late 2008 based on current operations or as early as 2007 if the NRC does grant permission to uprate the plant output. ENVY requires enabling legislation from the Vermont State Legislature and PSB approval for dry cask storage.

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 primarily using hydroelectric and biomass generation. 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 2004, IPP purchases accounted for 6.8 percent of the Company's total mWh purchased and 12.2 percent of purchased power expense. Purchases from IPPs are expected to be $18.7 million in 2005, $18.2 million in 2006, $19.1 million in 2007, $19.3 million in 2008 and $17.8 million in 2009. These amounts reflect annual savings of about $0.4 million related to the IPP settlement that is described in Note 13 to the Consolidated Financial Statements.

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. We enter into forward purchase contracts when additional supply is needed, such as for a Vermont Yankee nuclear plant refueling outage. We enter into forward sale contracts when we forecast excess supply and to minimize the net cost and risks of serving customers. On an hourly basis, power is sold or bought through ISO-New England to balance our resource output and load requirements, through the normal settlement process. On a monthly basis, we aggregate the hourly sales and purchases through ISO-New England and record them as Operating Revenue or Purchased Power, respectively.

Our long-term power forecast shows that energy purchase and production amounts exceed our load requirements. This is partly attributed to the January 1, 2004 termination of the power contract with Connecticut Valley, which made an annual average of about 15 MW previously used to source the contract available for load requirements or for resale. Because of this general increase, in November 2004, we entered two separate forward sale transactions, one through October 2006 and one through December 2008. Both contracts require physical delivery of power, but one is contingent upon Vermont Yankee plant output. We have assessed these two forward sale contracts and determined that one is a derivative under SFAS No. 133, and the other, due to the unit contingent nature of the transaction, is not a derivative. Our accounting for derivative power contracts is described in more detail in Critical Accounting Policies and Estimates above.

Based on existing commitments and contracts, we expect that net purchased power and production fuel costs will average about $122 million to $132 million per year for the years 2005 through 2009. These projections are dependent, in part, upon wholesale power market prices. Increases in the wholesale price should generally reduce our net power costs, while decreases should generally increase net costs.

We continue to monitor, and adapt to, changes to New England wholesale power markets and open access transmission systems. In March 2003, ISO-New England implemented Standard Market Design ("SMD"), a significant step to restructuring the wholesale energy markets in the Northeast. We use both the day-ahead and real-time markets in ISO-New England. The day-ahead energy market has generally seen slightly higher energy prices and lower price volatility than the real-time energy market. Operating reserve prices and their volatility have also generally been lower in the day-ahead market. We apply continuous improvement management techniques in managing our power supply resources and load obligations in SMD to minimize the net cost of power supply and related risks.

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Beginning May 1, 2004, we began to settle our power accounts with ISO-New England on a standalone (direct) basis. Up until this time, all Vermont utilities were settled at ISO-New England, and VELCO then performed the settlement within Vermont. With changes in power markets and NEPOOL/ISO rules and procedures, many of the benefits of a single Vermont settlement have disappeared, and direct settlement now provides advantages to us in terms of efficiency and cost savings.

Transmission-related matters 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 Regional Transmission Organizations ("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 us, filed a joint proposal with FERC to create an RTO for New England. That filing received conditional approval from FERC, and the RTO parties have reached agreement in principle to resolve certain outstanding issues with NEPOOL. The parties have requested that FERC expedite its decision processes on remaining issues, in particular, the rate of return that will be permitted on transmission investments.

On March 24, 2004, FERC conditionally approved the RTO filing. The RTO parties submitted a compliance filing to FERC in December 2004. In the filing, the Highgate facilities are classified as PTF with a five-year phase-in of Regional Network Service ("RNS") reimbursement treatment. At the end of the phase-in period, our net costs will be based on our load ratio rather than our ownership share of the facilities. This change is expected to significantly decrease our costs for RNS service related to that facility. Apart from the new RTO, we expect other transmission costs will increase due to growth in new transmission facilities in New England. The RTO began operations on February 1, 2005. Our share of savings related to the Highgate facilities are expected to be about $0.6 million in 2005, $1.0 million in 2006, $1.4 million in 2007, $1.7 million in 2008 and $2.1 million in 2009. At this time, we are not able to predict the impact of other transmission costs related to the RTO.

Transmission plays a significant role in the competitive wholesale 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 NEPOOL for shared cost treatment. Vermont has traditionally had higher-than-average transmission costs. The current approach provides cost and reliability benefits in providing service to our customers, because our load share is a small fraction of New England's load, and the facilities upgrades VELCO is planning improve the reliability and efficiency 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. Also, better reliability elsewhere in the region benefits Vermont's reliability because of the highly integrated nature of New England's high-voltage network. If other future transmission facil ities do not qualify for cost sharing, those costs will be charged only to the requesting entity and our share of such costs will be affected by FERC-approved cost-allocation rules contained in VELCO's and our tariffs and agreements.

VELCO bills us on a monthly basis for transmission and administrative costs associated with power and transmission services; these billings include various credits such as those from ISO-New England under the NEPOOL Open Access Transmission Tariff ("NOATT"). Such billings amounted to $6.3 million in 2004, $12.0 million in 2003 and $12.6 million in 2002, and are reflected as production and transmission expenses in the accompanying Consolidated Statements of Income. Prior to May 2004, VELCO also billed us for our share of NOATT charges, which are now billed directly to us from ISO-New England. Of the amounts billed to us by VELCO, about $5.3 million in 2004, $10.7 million in 2003 and $11.7 million in 2002 are included in VELCO's revenues. Accounts payable to VELCO amounted to $4.8 million at December 31, 2004 and $6.2 million at December 31, 2003.

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

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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 In January 2003, we, the Vermont Agency of Natural Resources ("Agency"), Vermont Natural Resources Council 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 recovery of replacement power costs when the dam is out of service. In July 2003, the Agency published its draft water quality certificate and in October 2003, pursuant to the schedule set forth in the agreement, we filed a petition with the PSB for approval of the rate recovery mechanisms. In April 2004, the PSB issued an order adopting a schedule intended to permit a final order in the fourth quarter of 2004. In the second quarter of 2004, at a public hearing, many residents of the Town of Milton opposed the dam's removal. The PSB held two additional public meetings in September 2004, and testimony was given in support of and opposition to removal of the power station. The case has continued to progress through the regulatory process, with some delay, and final technical hearings are now scheduled for March and April 2005. A final order is now expected in 2005. 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, and are responsible for paying our ownership percentage of decommissioning and all other costs for each plant. We also have a 1.7303 percent joint-ownership interest in Millstone Unit #3. Our obligations related to that plant are described in more detail in Note 13 - Commitments and Contingencies.

The Maine Yankee, Connecticut Yankee and Yankee Atomic nuclear plants have been shut down and are undergoing decommissioning. Information related to decommissioning and closure costs, including our share of estimated future payments 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. All three are parties to a lawsuit against the DOE seeking damages based on the DOE's default. The trial on determination of damages began on July 12 and ended August 31, 2004. Closing arguments were held in January 2005 and final post-trial briefs were filed in February 2005. A decision is expected by the end of 2005; however, an appeal by at least one of the parties is likely. None of the plants have included any allowance for potential recovery of these claims in their FERC-filed cost estimates.

Our share of Maine Yankee, Connecticut Yankee and Yankee Atomic estimated costs are reflected on the Consolidated Balance Sheets as regulatory assets or other deferred charges, and nuclear decommissioning liabilities (current and non-current). These amounts are adjusted when revised estimates are provided by the companies. At December 31, 2004, we had regulatory assets of about $5.8 million related to Maine Yankee and $2.1 million related to Connecticut Yankee. These estimated costs are being collected from our customers through existing retail rate tariffs. At December 31, 2004, we also had other deferred charges related to incremental dismantling costs of about $10.5 million for Connecticut Yankee and $7.2

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million for Yankee Atomic. These amounts include payments of about $0.1 million to Connecticut Yankee and $3.0 million to Yankee Atomic, representing our share of the respective companies' collection of incremental costs as of December 31, 2004. These incremental dismantling costs are not being recovered through existing retail rate tariffs, and are being deferred based on an October 2003 PSB-approved Accounting Order for treatment of these incremental costs as deferred charges, to be addressed in our pending rate proceeding.

Maine Yankee, Connecticut Yankee and Yankee Atomic collect decommissioning and closure costs through wholesale FERC-approved rates charged under power agreements with several New England utilities, including us. Historically, our share of these costs has been recovered from retail customers through PSB-approved rates. Based on the regulatory process, Management believes its share of decommissioning and closure costs for each plant will continue to be recovered through the regulatory process. Although Management believes that the decommissioning and closure costs will ultimately be recovered from its customers, there is a risk that the FERC may not allow full recovery of Connecticut Yankee's incremental increased costs in wholesale rates. If FERC does not allow these costs to be recovered in wholesale rates, we anticipate that the PSB would disallow these costs for recovery in retail rates as well. See discussion below for additional information related to Maine Yankee, Connecticut Yankee and Yankee A tomic.

Maine Yankee: We have a 2 percent ownership interest in Maine Yankee. Billings from Maine Yankee amounted to about $1.3 million in 2004, $1.1 million in 2003 and $1.1 million in 2002, and are included in Purchased Power on the Consolidated Statements of Income. Accounts Payable to Maine Yankee for 2004 and 2003 were of a nominal amount.

In October 2003, Maine Yankee filed a FERC rate proceeding for collection of estimated decommissioning and long-term spent fuel storage costs. In July 2004, Maine Yankee and various other parties agreed to an Offer of Settlement resolving all issues raised by the rate case participants. On September 16, 2004, FERC approved the settlement, which provides for recovery of all of Maine Yankee's forecasted costs of providing service through a formula rate contained in its power contracts through October 31, 2008 and replenishment of the DOE Spent Fuel Obligation through collections from November 2008 through October 2010.

From January 1 through October 31, 2004, Maine Yankee's billings to sponsor companies were based on its FERC filing subject to refund. Beginning November 1, 2004, Maine Yankee's billings have been based on the FERC-approved settlement, reduced for excess collections that occurred prior to the effective date.

Connecticut Yankee: We have a 2 percent ownership interest in Connecticut Yankee. Billings from Connecticut Yankee amounted to $0.9 million for 2004, $0.9 million for 2003 and $0.9 million for 2002, and are included in Purchased Power on the Consolidated Statements of Income. Accounts Payable to Connecticut Yankee for 2004 and 2003 were of a nominal amount. Costs currently billed by Connecticut Yankee are based on its most recent FERC-filed rates, which became effective February 1, 2005, for collection through 2010, subject to refund, and pending a final order by FERC. Prior to February 1, 2005, costs were billed by Connecticut Yankee based on its FERC-approved rates that became effective September 1, 2000, for collection through 2007.

Connecticut Yankee is currently involved in litigation related to a contract dispute. Also in 2004, Connecticut Yankee filed a rate application with FERC. These matters are discussed in more detail below.

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Our estimated aggregate obligation related to Connecticut Yankee is about $12.6 million. We continue to believe that FERC will approve recovery of these increased costs in wholesale rates based on the nature of costs and previous rulings at other nuclear companies. Once approved by FERC, we believe it is unlikely that the PSB would not allow these FERC-approved costs to be recovered in retail rates. If FERC adopts the CT DPUC's recommendations described above, our share of the proposed disallowance would be about $4.7 million. The timing, amount and outcome of the Bechtel litigation and FERC rate case filing cannot be predicted at this time.

Yankee Atomic: We have a 3.5 percent ownership interest in Yankee Atomic. Billings from Yankee Atomic amounted to $1.9 million for 2004 and $1.1 million for 2003, and are included in Purchased Power on the Consolidated Statements of

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Income. Accounts Payable to Yankee Atomic for 2004 and 2003 were of a nominal amount. Billings from Yankee Atomic ended in July 2000 based on Yankee Atomic's determination that it had collected sufficient funds to complete the decommissioning effort. We are not currently collecting Yankee Atomic costs in retail rates.

In April 2003, Yankee Atomic filed with FERC, based on updated cost estimates, 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. On August 6, 2003, Yankee Atomic filed a Settlement Agreement that resolved all issues raised by the parties. Beginning April 2004 and each year following, the new rates are subject to an annual adjustment based on the prior calendar year's data if the decommissioning trust fund market performance is 10 percent greater or 10 percent less than the assumptions used to calculate the schedule of decommissioning charges. As such, a reduction was applied to filed-rates beginning with April 2004 billings.

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

Catamount As of December 31, 2004, Catamount has interests in six operating independent power projects located in Rumford, Maine; East Ryegate, Vermont; Hopewell, Virginia; Nolan County, Texas; Thuringen, Germany and Mecklenburg-Vorpommern, Germany.

Catamount is wholly focused on development, ownership and asset management of wind energy projects. Wind energy is competitive with other forms of electric generation and has low production costs compared to other renewable energy sources. Environmental and energy security concerns in the United States and United Kingdom support growth in the wind sector. Depending on prices, capital and other requirements, Catamount will entertain offers for the purchase of certain of its wind electric generating assets and any of its remaining non-wind electric generating assets. Additionally, Catamount is seeking investors and partners to co-invest with Catamount in the development, ownership and acquisition of projects, which will be financed by equity and non-recourse debt. Management cannot predict the timing or outcome of potential future asset sales or whether this strategy will be successful.

Catamount has projects under development in the United States and United Kingdom. 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. The issuance resulted in no gain or loss.

In 2004, Catamount entered into a joint development arrangement with Marubeni Power International, Inc. The arrangement represents an exclusive agreement for wind energy development throughout New England, New York and Pennsylvania.

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

Catamount Results

Catamount's 2004 earnings totaled $3.6 million, including $2.9 million of net income tax benefits and $1.5 million of after-tax gains associated with the sales of the Fibrothetford, Rupert and Glenns Ferry investment interests. Also included was a fee associated with Catamount's United Kingdom development effort. Catamount's 2003 earnings were $0.7 million, including a $2.3 million reduction of income tax valuation allowances associated with previously recorded equity losses resulting from asset impairment for the Fibrothetford, Rupert and Glenns Ferry investments. The 2003 reduction in income tax valuation allowances resulted in a benefit to the consolidated federal income tax provision due to management's best estimate that the Company would receive capital gains treatment on the Connecticut Valley sale. Catamount's 2002 earnings totaled $1.5 million.

Catamount, or its wholly owned subsidiaries, provide certain management, accounting and other services to certain entities in which Catamount holds an equity interest. The fees are designed to recover actual costs or are agreed upon by other equity investors in these entities. All fees are billed monthly with the exception of one that is billed annually. Additionally, all fees are payable monthly except for one in which fees are payable upon receipt of dividends from its wholly owned subsidiaries. Catamount's revenues, included in Other Income on the Consolidated Statements of Income, included billings of $0.6 million in 2004, $0.5 million in 2003 and $0.6 million in 2002. Accounts Receivable for these billings amounted to $0.6 million in

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2004, of which $0.5 million has been reserved for 2004, and $0.2 million in 2003. Also included in Catamount's 2004 Accounts Receivable are fees of about $0.5 million from a windfarm under construction in which Catamount has an ownership interest.

Information regarding certain of Catamount's investments follows.

Appomattox In October 2004, the partnership's long-term lease with the steam host ended. The partnership is finalizing its business operations and in December 2004, most of the project's remaining cash was distributed to the partners. In December 2004, Catamount recorded a nominal impairment associated with its general partner interest in the partnership.

Glenns Ferry and Rupert On July 1, 2004, Catamount completed the sale of its investment interests in Glenns Ferry and Rupert to a third party. The sale resulted in an after-tax gain of about $0.6 million and an additional $0.2 million of income tax benefits associated with the sale. As described above, in the third quarter of 2003, Catamount recorded a $0.6 million benefit related to the reduction of income tax valuation allowances associated with its investments in Glenns Ferry and Rupert.

Sweetwater 1 In December 2003, Catamount acquired an equity interest of $6.2 million in Sweetwater Wind 1 LLC, a 37.5-MW wind farm in Nolan County, Texas. Sweetwater Wind 1 LLC commenced commercial operations on December 23, 2003.

Sweetwater 2 In February 2005, Catamount acquired an equity interest of $15.4 million in Sweetwater Wind 2 LLC, a 91.5-MW wind farm in Nolan County, Texas. Sweetwater Wind 2 LLC commenced commercial operations on February 11, 2005.

Fibrothetford Limited In September 2004, Catamount entered into separate Sales and Purchase Agreements with a third party for the sale of its Fibrothetford note receivable and its equity investment. The note receivable was sold in September 2004, resulting in an after-tax gain of $0.6 million. Its equity investment was sold in October 2004, resulting in an after-tax gain of about $0.3 million. Both the sale of the note receivable and equity investment resulted in additional income tax benefits of $0.2 million and $2.5 million, respectively. As described above, in the third quarter of 2003, Catamount recorded a $1.7 million benefit related to the reduction of income tax valuation allowances associated with its investments in Fibrothetford.

In December 2002, 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 that Sale and Purchase Agreement.

To the extent required, continuing equity losses were applied as a reduction to Catamount's note receivable balance from Fibrothetford. In 2004 and 2003, Catamount reserved approximately $1.7 million and $2 million, respectively, against interest income on the note receivable.

DK Burgerwindpark Eckolstadt and DK Windpark Kavelstorf GmbH&Co. KG (collectively "Eurowind") In December 2004, Catamount recorded an after-tax impairment of $0.2 million related to its Eurowind investments. The impairment reflects Management's best estimate of the current market value of these investments.

Heartlands Power Limited ("Heartlands") In the third quarter of 2002 Catamount recorded an after-tax investment impairment charge to earnings of $1.3 million related to the pending sale of its equity investments in Heartlands. On October 30, 2002, Catamount sold its 50 percent interest in Heartlands. The proceeds from the sales approximated the net book value of its investment.

Gauley River Catamount entered into a Purchase and Sale Agreement, dated June 30, 2002, with a third party, for sale of its Gauley River investment interests. In the third quarter of 2002, Catamount recorded a $0.8 million after-tax impairment charge to earnings based on funding certain escrow accounts as a condition of the Purchase and Sale Agreement. The sale was consummated on December 5, 2002 and the proceeds from the sale approximated net book value of its Gauley River investment interests.

Eversant As of December 31, 2004, Eversant had a $1.4 million equity investment, representing a 12 percent ownership interest in The Home Service Store Inc. ("HSS"). HSS has established a network of affiliate contractors who perform home maintenance repair and improvements for its members. Eversant accounts for this investment on the cost basis.

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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 $0.4 million in 2004, $0.5 million in 2003 and $0.3 million in 2002.

Overall, Eversant's earnings were $0.4 million in 2004 and $0.5 million in 2003, versus a net loss of $0.5 million in 2002. In early 2002, we discontinued Eversant's efforts to pursue unregulated business opportunities except for SEWHS.

INCOME TAX MATTERS
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. For the periods ended 2004 and 2003, the valuation allowances recorded were $0.9 million and $0.8 million respectively for certain losses related to Catamount's foreign investments. Management added $0.1 million to the valuation allowances for certain foreign losses incurred in 2004 related to Catamount's foreign investments after it determined that it is more likely than not that a current or future income tax benefit would not be realized.

For 2003, the valuation allowances were decreased by $3.4 million. 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. The valuation allowances were also reduced by $1.9 million due to the reclassification of an equity method of accounting adjustment related to the financial statements from one of Catamount's foreign projects. The valuation allowances were increased by $0.8 million for certain foreign losses related to Catamount's foreign investments. Management determined that it was more likely than not that a current or future income tax benefit would not be realized.

     See Note 1 to the accompanying Consolidated Financial Statements.

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

We consider our most significant risks to be 1) regulatory risk as it relates to timely and full recovery of costs to serve our customers, and 2) wholesale power market risks given that we rely on two long-term contracts that support about 75 percent of our load requirements. Due to cost-based-rate regulation, the Vermont utility business has limited exposure to market volatility in interest rates. For a discussion of regulatory risk and the risks associated with our unregulated business, Catamount, see Item 7, Vermont Retail Rates and Business Risk. Below is a discussion of the primary market-related risks associated with our core business.

Wholesale Power Market Risk Our most significant power supply contracts are with Hydro-Quebec and Vermont Yankee Nuclear Power Corporation. Combined, these contracts amounted to about 84 percent of our total energy (mWh) purchases in 2004. The contracts are described in more detail in Item 7, Power Supply Matters. Summarized information regarding these contracts follows.

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We have other power contracts that we account for under the guidance of SFAS No. 133. Summarized information related to unrealized gains and losses on energy-related derivatives is shown in the table below (in thousands):

Changes in fair value of these derivatives are recorded as deferred charges or deferred credits on the Consolidated Balance Sheets depending on whether the fair value is an unrealized loss or gain, with an offsetting amount recorded as a decrease or increase in the related derivative asset or liability. See Item 7, Critical Accounting Policies and Estimates for a discussion of derivative financial instruments.

Pension  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. See Item 7, Critical Accounting Policies and estimates, and Note 10 to the Consolidated Financial Statements for additional information related to Pension and Postretirement Benefits.

Equity Market Risk As of December 31, 2004, our pension trust held marketable equity securities in the amount of $44.3 million and our Millstone Unit #3 decommissioning trust held marketable equity securities of $3.5 million. We also maintain a variety of insurance policies in a Rabbi Trust with a current value of $6 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, 2005. These letters of credit support three series of Industrial Development Revenue Bonds, totaling $16.3 million.

Based on outstanding debt at December 31, 2004, 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 quarters of 2004 and 2003, we recorded $2 million in Restricted Cash related to December 2004 and December 2003 payments to the Transfer Agent for the annual $1 million mandatory sinking fund payments and a $1 million optional payment for each year. The payments to the Preferred Shareholders were made effective January 1, 2005 and January 1, 2004.

The covenants covering our First 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.

Interest Rate Risk As of December 31, 2004, we had $16.3 million of Industrial Development Revenue 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.

The table below provides information about interest rates on our long-term debt and Industrial Development Revenue bonds.