SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549

|  X  |      QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended     March 31, 2003    

|     |      TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______ to _______

Commission file number     1-8222

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

        Incorporated in Vermont                          03-0111290        
(State or other jurisdiction of                     (I.R.S. Employer
incorporation or organization)                    Identification No.)

        77 Grove Street, Rutland, Vermont            05701        
(Address of principal executive offices)       (Zip Code)

                              802-773-2711                              
(Registrant's telephone number, including area code)

                                                                                                         
(Former name, former address and former fiscal year, if changed since last report)

      Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes   X     No       

      Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. As of April 30, 2003 there were outstanding 11,838,564 shares of Common Stock, $6 Par Value.

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Form 10-Q - 2003

Table Of Contents

CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
(Dollars in thousands, except per share amounts)
(unaudited)

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

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CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
(unaudited)

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

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About Central Vermont Public Service Corporation  Central Vermont Public Service Corporation ("the Company" or "CVPS") is an electric utility business based in Vermont which distributes, transmits and markets electricity and invests in renewable and independent-power generation projects. The Company's wholly owned subsidiaries include Connecticut Valley Electric Company ("Connecticut Valley"), which distributes and sells electricity in parts of New Hampshire; Catamount Energy Corporation ("Catamount"), which invests primarily in wind energy projects in the United States and Western Europe; and Eversant Corporation ("Eversant"), which operates a rental water heater business through its subsidiary, SmartEnergy Water Heating Services, Inc.

     On April 8, 2003, the Company filed a petition with the Vermont Public Service Board ("PSB"), to transfer its shares of Vermont Yankee Nuclear Power Corporation to Custom Investment Corporation ("Custom"), a wholly owned passive investment subsidiary. The Company also intends to transfer its interests in Maine Yankee, Connecticut Yankee and Yankee Atomic to Custom.

     The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by accounting principles generally accepted in the United States of America for financial statements. In Management's opinion all adjustments considered necessary for a fair presentation have been included. Operating results for the quarter ended March 31, 2003 are not necessarily indicative of the results that may be expected for the twelve months ended December 31, 2003. For further information, refer to the consolidated financial statements and footnotes thereto included in the Company's annual report on Form 10-K for the year ended December 31, 2002 and the Company's Securities and Exchange Commissio n filings.

Stock Based Compensation The Company applies Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and related Interpretations in accounting for its stock option plans. The Company adopted the disclosure-only provisions of Statement of Accounting Standards ("SFAS") No. 123, Accounting for Stock-Based Compensation, as amended by SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of SFAS No. 123. The following table illustrates the effect on net income and earnings per share as if the fair value method had been applied to all outstanding and unvested awards in each period. The fair value of options at date of grant was estimated using the binomial option-pricing model.

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

Recent Accounting Pronouncements

Asset Retirement Obligations: In August 2001, the Financial Accounting Standards Board ("FASB") approved the issuance of SFAS No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143"). This statement provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of long-lived assets and requires entities to record the fair value of a liability for an asset retirement obligation ("ARO") in the period in which it is incurred. The Company adopted SFAS No. 143 on January 1, 2003 as required and did not have a cumulative effect upon adoption.

     The Company has legal retirement obligations associated with decommissioning related to its investments in nuclear plants, certain of its jointly owned generating plants and certain Catamount investments. The Company's regulated operations also collect removal costs in rates for certain utility plant assets that do not have associated legal asset retirement obligations. As of March 31, 2003, approximately $4.3 million related to non-legal removal costs is recorded in Accumulated Depreciation.

Variable Interest Entities: In January 2003, the FASB issued Interpretation 46, Consolidation of Variable Interest Entities. This standard will require an enterprise that is the primary beneficiary of a variable interest entity to consolidate that entity. The Interpretation must be applied to any existing interests in variable interest entities beginning in the third quarter of 2003. The Company does not expect to consolidate any existing interests in unconsolidated entities pursuant to requirements of Interpretation 46.

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     The Company is subject to regulation by the PSB, the New Hampshire Public Utilities Commission ("NHPUC") and the Federal Energy Regulatory Commission ("FERC"), with respect to rates charged for service, accounting and other matters pertaining to regulated operations. As such, the Company currently prepares its financial statements in accordance with SFAS No. 71, Accounting for the Effects of Certain Types of Regulation ("SFAS No. 71"), for its regulated Vermont service territory, FERC-regulated wholesale business and Connecticut Valley's New Hampshire service territory. Management periodically reviews these criteria to ensure the continuing application of SFAS No. 71 is appropriate. Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, Management believes future recovery of regulatory assets in the State of Vermont and State of New Hampshire for the Company's retail and wholesale businesses is proba ble.

     Under SFAS No. 71 the Company accounts for certain transactions in accordance with permitted regulatory treatment. As such, regulators may permit incurred costs, typically treated as expenses by unregulated entities, to be deferred and expensed in future periods when recovered in future revenues. In the event that the Company no longer meets the criteria under SFAS No. 71 and there is not a rate mechanism to recover these costs, the Company would be required to write off related regulatory assets, certain other deferred charges and regulatory liabilities as summarized in the following table (dollars in thousands):

     On January 1, 2003, based on PSB approval and in accordance with its June 2001 rate case settlement, the Company began recording the collection of Millstone Unit #3 decommissioning non-payments as a regulatory liability. The Millstone Unit #3 decommissioning non-payments resulted because the Company's share of contributions to the Millstone Unit #3 Trust Fund ceased in 2001 even though those amounts are being collected in rates. In 2002, the accumulated collection amount was applied to reduce certain regulatory assets related to

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Conservation and Load Management per PSB approval. At March 31, 2003 the regulatory liability is approximately $0.1 million and will continue to increase unless rates are adjusted to exclude such collections or the Company chooses or is required to renew funding in the future. This regulatory liability, including carrying charges, will be addressed in the Company's next rate proceeding.

     In the first quarter of 2003, as a result of the Independent Power Producers ("IPP") settlement, which is described in Note 6, Commitments and Contingencies, the Company was reimbursed for legal costs from non-participating parties to the IPP negotiations who share in the benefits. Based on the PSB's approval of the IPP settlement, the Company has requested an accounting order that will result in recording the savings credits as a regulatory liability, including carrying charges, to be addressed in its next rate proceeding. At March 31, 2003 the regulatory liability is approximately $0.3 million.

     In the first quarter of 2003, the Company filed a request with the PSB for an Accounting Order in connection with its utility earnings cap requirement. In 2002 the Vermont utility earned approximately $0.4 million, on an after-tax basis, above its allowed rate of return on common equity of 11 percent. In accordance with its June 2001 rate case settlement, the Company reduced the Vermont utility's earnings by that amount to satisfy its earnings cap requirement. The related deferral of approximately $0.7 million pre-tax is included in Other deferred credits on the Condensed Consolidated Balance Sheet. The Company requested that the PSB approve the treatments of excess earnings as a regulatory liability to be addressed in its next rate proceeding.

Vermont Yankee Nuclear Power Corporation ("Vermont Yankee" or "VYNPC") Summarized financial information for VYNPC is as follows (dollars in thousands):

     In January 2002, Vermont Yankee settled with secondary purchasers and also agreed to buy out minority stockholders. As a result, the Company's ownership rose from 31.3 percent to 33.23 percent.

     On July 31, 2002, Vermont Yankee completed the sale of its assets to Entergy Nuclear Vermont Yankee, LLC ("Entergy"), and Entergy assumed the decommissioning liability for the plant and its decommissioning trust fund. The agreement included a purchased power contract ("PPA") with prices generally ranging from 3.9 cents to 4.5 cents per kilowatt-hour through 2012. Starting in November 2005, the PPA will include a mechanism that lowers the power costs if market prices drop significantly. If market prices rise, the contract prices do not change.

     The sale required various regulatory approvals, all of which were granted on terms acceptable to the parties to the transaction. Certain intervenor parties to the PSB approval proceeding appealed the PSB approval to the Vermont Supreme Court. That appeal is pending. If the appellants prevail on their appeal, the PSB could be required to conduct additional proceedings or to reconsider its order approving the sale.

     The Company has a 33.23 percent equity interest in VYNPC, which administers the purchased power contracts among the former plant owners and Entergy. The Company receives its 35 percent entitlement of Vermont Yankee output sold by Entergy to VYNPC and one remaining secondary purchaser continues to receive a small percentage of the Company's entitlement. Under the PPA between Entergy and VYNPC, VYNPC pays Entergy only for generation at fixed rates; VYNPC in turn bills the PPA charges from Entergy with certain residual costs of service through a FERC tariff to the Company and the other VYNPC sponsors.

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     Although the sale closed on July 31, 2002, final accounting for the sale is pending certain regulatory approvals and resolution of certain closing items between the seller and purchaser. Cash distributions related to the sale will be received in 2003 or 2004.

     Vermont Yankee's revenues shown in the table above include sales to the Company of $16.7 million and $12.6 million for the first quarter of 2003 and 2002, respectively. These amounts are reflected as purchased power and for 2002 are shown net of deferrals and amortization, in the Company's Condensed Consolidated Statements of Income. The Company no longer bears the operating costs and risks associated with running the plant or the costs and risk associated with the eventual decommissioning of the plant.

Vermont Electric Power Company, Inc. ("VELCO") Summarized financial information for VELCO is as follows (dollars in thousands):

     As a result of other owners acquiring additional shares of VELCO's Class C common stock, the Company's common stock ownership in VELCO changed from 56.8 percent to 50.6 percent in the third quarter of 2002.

     VELCO's revenues shown above include transmission services to the Company (reflected as production and transmission expenses in the Company's Condensed Consolidated Statements of Income) amounting to $3.2 million and $3.0 million in the first quarter of 2003 and 2002, respectively.

     Catamount invests through its wholly owned subsidiaries in non-regulated energy generation projects in the United States and Western Europe. As of March 31, 2003 through its wholly owned subsidiaries, Catamount has interests in eight operating independent power projects located in Glenns Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont; Thetford, England; Hopewell, Virginia; Thuringen, Germany and Mecklenburg-Vorpommern, Germany.

     Catamount's loss and earnings were $0.1 million and $0.5 million for the first quarter of 2003 and 2002, respectively.  Catamount is currently pursuing the sale of certain of its interests in non-wind electric generating assets.  Information regarding certain of Catamount's investments follows.

Heartlands Power Limited  On October 30, 2002, Catamount sold its 50 percent interest in Heartlands Power Limited to a third party. The proceeds from the sale approximated the net book value of its investments.

Gauley River  The sale of Gauley River was consummated on December 5, 2002 and proceeds from the sale approximated the net book value of its investments.

Fibrothetford Limited Continuing equity losses have been applied as a reduction to Catamount's note receivable balance from Fibrothetford. For the first quarter of 2003 and 2002, Catamount reserved $0.4 million and $0.3 million, respectively, of note receivable interest income.

     On December 30, 2002, Catamount entered into a Sale and Purchase Agreement with a third party for the sale of its Fibrothetford investment interests. The buyer could have terminated the Agreement if the sale was not consummated prior to March 31, 2003. The sale has not been completed to date; however, the buyer has notified

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Catamount that they want to proceed with the purchase of Catamount's Fibrothetford interests. Catamount expects the sale to occur in 2003 and expects the proceeds from the sale to approximate the net book value of its investments in Fibrothetford.

Glenns Ferry and Rupert Both Rupert and Glenns Ferry were issued an Events of Default notice by their lender in May 2002. Steam host restructurings in 2002 cured most of the events of default identified in the Events of Default notices. Rupert cured its remaining events of default in March 2003 and management anticipates that Glenns Ferry will cure its remaining events of default in the late second or early third quarter of 2003.

     The Company recognizes adequate and timely rate relief is required to maintain its financial strength, particularly since Vermont law does not allow power and fuel costs to be passed to consumers through fuel adjustment clauses. The Company will continue to review costs and request rate increases when warranted. In May 2002, the Company announced planned cost-cutting efforts and its intent to refrain from changing rates before 2006 absent unforeseen developments.

Vermont Retail Rates On June 26, 2001, the PSB approved a settlement with the DPS, including a 3.95 percent increase effective July 1, 2001. As part of the settlement, the Company 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 ended uncertainty over Hydro-Quebec 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. The rate order requires CVPS to return up to $16 million to ratepayers if there is a merger, acquisition or asset sale that requires PSB approval.

     On October 4, 2002, the PSB approved the Company's proposal to reduce regulatory assets by $2 million, using the remaining Hydro-Quebec settlement and funds collected for Millstone Unit #3 decommissioning. The Company is recovering the decommissioning costs in rates, but its decommissioning payments currently have ended. In the third quarter of 2002, based on the PSB Order, the Company reduced regulatory assets related to Conservation and Load Management by approximately $2 million. In January 2003, the Company began recording the Millstone Unit #3 decommissioning non-payments as a regulatory liability, with carrying charges. They will be addressed in the Company's next rate proceeding.

     In 2002, the Vermont utility earned approximately $0.4 million, after-tax, above its allowed rate of return on common equity of 11 percent. The Vermont utility's earnings were reduced by that amount to stay at the earnings cap. The related deferral of about $0.7 million pre-tax is included in Other deferred credits on the Condensed Consolidated Balance Sheet. The Company filed for an accounting order with the PSB requesting approval for the treatments of excess earnings as a regulatory liability to be addressed in its next rate proceeding.

     In accordance with the PSB's Order approving the sale of the Vermont Yankee assets, on April 15, 2003, the Company filed Cost of Service Studies for rate years 2003 and 2004 to determine whether a rate decrease is appropriate in either year. The Company cannot predict whether the PSB will open a rate investigation based upon the Cost of Service Studies, or if opened, whether an investigation would result in a rate increase or decrease.

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

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

     On April 16, 2003, the NHPUC approved Connecticut Valley's April 2, 2003, request for an Interim PPCA to reduce a potential overcollection during the remainder of 2003. As a result of this approval, to be effective May 1, 2003, Connecticut Valley's rates will decrease 6.3 percent, and revenues will decrease $0.8 million.

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Connecticut Valley Sale On December 5, 2002, the Company agreed to sell Connecticut Valley's assets to Public Service Company of New Hampshire ("PSNH"). The agreement resulted from months of negotiations with the Governor's Office of Energy and Community Services, NHPUC staff, the Office of Consumer Advocate, the City of Claremont and New Hampshire Legal Assistance. The sale is intended to resolve all Connecticut Valley restructuring litigation in New Hampshire and the Company's stranded cost litigation at FERC. The sale is expected to close January 1, 2004.

     PSNH will pay book value for Connecticut Valley's franchise and assets, which approximates $9 million at December 31, 2002. PSNH will acquire Connecticut Valley's poles, wires, substations and other facilities, and several independent power obligations, including the Wheelabrator contract. PSNH will also pay the Company $21 million for stranded power costs.

     The FERC and the NHPUC must approve the sale. The NHPUC must also approve the pending settlement with Wheelabrator for the sale to close.

     On January 31, 2003, Connecticut Valley, the Company, PSNH and various other parties asked the NHPUC for approval of settlements and transactions related to the sale. The parties are seeking approval to implement restructuring in Connecticut Valley's service territory after the sale is completed, resolve litigation between the NHPUC, Connecticut Valley and the Company, and complete the sale. Under the proposed schedule, an Order would be issued by the end of June 2003. The Company anticipates the New Hampshire legislature will pass the necessary legislation enabling PSNH's recovery of costs for the sale; the Governor is scheduled to sign the legislation on May 20, 2003.

     The sale could result in a gain or loss and is highly dependent on power market price forecasts at the time of the sale. At this time, Management cannot estimate whether the sale will result in a gain or loss.

     If the sale transaction does not close, and the FERC exit fee proceeding, described below, ends unfavorably, there would be a material adverse effect on the Company's results of operations, financial condition and cash flows. Management cannot predict the outcome of this matter.

     See Note 8, Segment Reporting, for additional information related to Connecticut Valley.

FERC Exit Fee Proceedings On February 28, 1997, the NHPUC told Connecticut Valley to stop buying power from the Company. The Company asked for FERC approval, in June 1997, for a transmission rate surcharge to recover stranded costs if Connecticut Valley canceled the rate schedule. In December 1997, FERC rejected the proposal, but said it would consider an exit fee if the contract was canceled. A rehearing motion was denied, so the Company applied for an exit fee totaling $44.9 million as of December 31, 1997.

     On April 24, 2001, a FERC Administrative Law Judge ("ALJ") issued an Initial Decision, ruling that if Connecticut Valley terminates its wholesale contract and becomes a wholesale transmission customer of the Company, Connecticut Valley must pay stranded costs to the Company. For illustration, the ALJ calculated that payment at nearly $83 million through 2016. The exit fee decreases annually if service continues, and will be recalculated if the wholesale contract ends.

     On October 29, 2002, the Company and NHPUC asked FERC to withhold its final exit fee order so the parties could continue negotiating a settlement. On December 5, 2002, Connecticut Valley, the Governor's office, the City of Claremont, NHPUC staff and PSNH agreed on the sale of Connecticut Valley's assets to PSNH. The agreement, described in detail above, would make the FERC decision moot.

     Absent the sale, if Connecticut Valley had to end its contract with the Company and no exit fee was approved, the Company would have to recognize a pre-tax loss of about $27.4 million as of Dec. 31, 2004. That is the earliest termination could occur under the rate schedule. Additionally, the Company would have to write-off approximately $0.6 million pre-tax of regulatory assets. The sale of Connecticut Valley to PSNH, which includes the receipt of $21 million in stranded costs, would resolve these issues. Management cannot predict whether the sale will occur under these or other terms.

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Wheelabrator Power Contract Connecticut Valley purchases power from several Independent Power Producers, who own qualifying facilities as defined by the Public Utility Regulatory Policies Act of 1978. In the first quarter of 2003, Connecticut Valley bought 9,055 mWh under long-term contracts with these facilities, 96 percent from Wheelabrator Claremont Company, L.P., ("Wheelabrator") which owns a trash-burning generating facility. Connecticut Valley had filed a complaint with FERC stating its concern that Wheelabrator has not been a qualifying facility since the facility began operation. On February 11, 1998, FERC denied Connecticut Valley's request for a refund of past power costs and lower future costs. Connecticut Valley's request for a rehearing was denied. Connecticut Valley appealed to the D.C. Circuit Court of Appeals. It denied the appeal, but said Connecticut Valley could seek relief from the NHPUC. On May 12, 2000, Connecticut Valley asked the NHPUC to amend the contract to permit purchase of only net output of the facility. Connecticut Valley also sought a refund, with interest, for purchases of the difference between net and gross output.

     On March 29, 2002, the NHPUC denied Connecticut Valley's petition. The NHPUC found that its original 1983 order did not authorize sales in excess of 3.6 MW and ordered Connecticut Valley to stop any additional purchases. Wheelabrator has been making sales of up to 4.5 MW of capacity and related energy since 1987.

     On April 29, 2002, Connecticut Valley, Wheelabrator, NHPUC Staff and the Office of Consumer Advocate submitted a settlement with the NHPUC, requiring Wheelabrator to make five annual payments of $150,000 and a sixth payment of $25,000, and Connecticut Valley to make six annual payments of $10,000, to be credited to customer bills. The settlement requires NHPUC approval. It does not change the contract between Connecticut Valley and Wheelabrator.

     A hearing on the settlement was held June 7, 2002. The NHPUC issued an Order on July 5, 2002, but did not rule on the settlement. Instead, the NHPUC said it would appoint a mediator to work with all parties to see if a new settlement could be reached. The NHPUC selected a mediator and, after several mediation sessions, the mediator issued a report on December 18, 2002. The opponents still oppose the settlement.

     The NHPUC must approve the settlement for the sale of Connecticut Valley to close. Through the sale, PSNH will acquire Connecticut Valley's independent power obligations, including the Wheelabrator contract.

Nuclear Decommissioning The Company is responsible for paying its 1.7303 joint-ownership percentage of Millstone Unit #3 decommissioning costs and its entitlement percentages of 2, 2 and 3.5 percent of decommissioning costs related to Maine Yankee, Connecticut Yankee and Yankee Atomic, (the "Yankee companies"), respectively.

Millstone Unit #3 The Company's contributions to the Millstone Unit #3 Trust Fund ceased in 2001, based on the lead owners representation to various regulatory bodies that the Trust Fund, for its share of the plant, exceeded the Nuclear Regulatory Commission's minimum calculation required. The Company could choose to renew funding at its discretion as long as the minimum requirement is met or exceeded.

Yankee companies The Company is one of several sponsor companies with ownership interests in Maine Yankee, Connecticut Yankee and Yankee Atomic. These companies have been permanently shut down and are currently conducting decommissioning activities. The Company is responsible for paying its entitlement shares, which are equal to its ownership percentages, of decommissioning costs for all three plants.

     Each plant revises its revenue requirement forecasts on an ongoing basis, which reflect the future payments required by sponsor companies to recover estimated decommissioning and all other costs. Based on revised estimates in 2002, Maine Yankee decommissioning costs increased by $40 million and Connecticut Yankee decommissioning costs increased by $150 million, respectively, over prior estimates utilized at FERC. Based on a 2003-update, Yankee Atomic's decommissioning costs are now forecast at $188 million. These increases are due mainly to increases in the projected costs of spent fuel storage, security and liability and property insurance.

     The Company's shares of estimated revenue requirements for each plant are reflected on the Condensed Consolidated Balance Sheets as either regulatory assets or other deferred charges, depending on current recovery in existing rates, and nuclear decommissioning liabilities (current and non-current). At March 31, 2003, the Company

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had regulatory assets of approximately $8.7 million and $3.6 million related to Maine Yankee and Connecticut Yankee, respectively, and other deferred charges of approximately $3.5 million and $7.9 million related to Connecticut Yankee and Yankee Atomic, respectively. These amounts are subject to ongoing review and revisions and the Company will adjust the associated regulatory assets, other deferred charges and nuclear decommissioning liabilities accordingly.

     The decision to prematurely retire these nuclear power plants was based on economic analyses of costs of operating them compared to costs of closing them and incurring replacement power costs over the remaining period of the plants' operating licenses. The Company believes that the premature retirements would have the effect of lowering costs to customers and based on the current regulatory process, its proportionate share of Maine Yankee's, Connecticut Yankee's and Yankee Atomic's decommissioning costs will be recovered through the regulatory process. Therefore, the ultimate resolution of the premature retirement of the three plants has not and should not have a material adverse effect on the Company's earnings or financial condition.

Maine Yankee Costs billed by Maine Yankee, including a provision for ultimate decommissioning of the plant, are expected to be paid over the period 2003 through 2008, and are being collected from the Company's customers through existing retail and wholesale rate tariffs.

     Maine Yankee's current billings to sponsor companies are based on their most recent rate case settlement, approved by FERC on June 1, 1999. Under the rate case settlement, Maine Yankee agreed to file with FERC a rate proceeding with an effective date for new rates of no later than January 1, 2004. The Company expects that Maine Yankee will seek recovery of the incremental cost increase described above in their next FERC rate filing.

Connecticut Yankee Costs billed by Connecticut Yankee, including a provision for ultimate decommissioning of the plant, are expected to be paid over the period 2003 through 2007 and are being collected from the Company's customers through existing retail and wholesale rate tariffs.

     Connecticut Yankee's current billings to sponsor companies are based on their most recent FERC-approved rates, which became effective September 1, 2000. The Company expects that Connecticut Yankee will seek recovery of the incremental cost increase described above in their next scheduled FERC rate filing.

Yankee Atomic Billings to sponsor companies ended in July 2000 based on Yankee Atomic's determination that it had collected sufficient funds to complete the decommissioning effort. Therefore the Company is not currently collecting costs in its existing rates.

     Yankee Atomic made a filing to FERC in April 2003 for rates effective June 2003 with collections from sponsor companies from June 2003 through December 2010. The Company expects its share of these costs to be approximately $1.1 million in 2003 and that these costs will be recoverable in future rates.

Environmental   Over the years, more than 100 companies have merged into or been acquired by CVPS. At least two of the companies used coal to produce gas for retail sale. This practice ended more than 50 years ago. Gas manufacturers, their predecessors and the Company used waste disposal methods that were legal and acceptable then, but may not meet modern environmental standards and could represent liability.

     Some operations and activities are inspected and supervised by federal and state authorities, including the Environmental Protection Agency. It is Company policy to comply with all environmental laws. The Company believes that it is in compliance with all laws and regulations and has implemented procedures and controls to assess and assure compliance. Corrective action is taken when necessary. Below is a brief discussion of known material issues.

Cleveland Avenue Property The Cleveland Avenue property in Rutland, Vermont, was used by a predecessor to make gas from coal. Later, the Company sited various operations there. Due to coal tar deposits, Polychlorinated Biphenyl contamination and potential off-site migration, the Company conducted studies in the late 1980s and early 1990s to quantify the situation. Investigation has continued, and the Company is working with the State of Vermont to develop a mutually acceptable solution.

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Brattleboro Manufactured Gas Facility In the 1940s, the Company owned and operated a manufactured gas facility in Brattleboro, Vermont. The Company ordered a site assessment in 1999 on request of the State of New Hampshire. In 2001, New Hampshire said no further action was required, though it reserved the right to require further investigation or remedial measures. In 2002, the Vermont Agency of Natural Resources notified the Company that its corrective action plan for the site, including groundwater monitoring and controls, was approved. That plan is now in place.

Dover, New Hampshire, Manufactured Gas Facility In 1999, PSNH contacted the Company about this site. PSNH alleged that the Company was partially liable for cleanup, since the site was previously operated by Twin State Gas and Electric ("Twin State"), which merged into CVPS the day PSNH bought the facility.

     The Company agreed to non-binding mediation regarding liability. Lengthy mediation followed with numerous parties, including the New Hampshire Department of Environmental Services ("NHDES"). A settlement with PSNH was reached, in which certain liabilities the Company might have had were assigned to PSNH in return for a cash payment. As a result, the Company reversed $1.7 million in environmental reserves in the second quarter of 2002.

     As of March 31, 2003 a reserve of $7.4 million is recorded on the Condensed Consolidated Balance Sheet. This represents Management's best estimate of the cost to remedy issues at these sites.  There is no pending or threatened litigation regarding other sites with the potential to cause material expense. No government agency has sought funds from the Company for any other study or remediation.

Independent Power Producers   The Company receives power from several Independent Power Producers ("IPPs"). These plants use water, biomass and trash as fuel. Most of the power comes through a state-appointed purchasing agent, VEPP Inc. ("VEPPI"), which assigns power to all Vermont utilities under PSB rules. In the first quarter of 2003, the Company received 41,311 mWh, which accounts for 6 percent of the total mWh purchased and 11.8 percent of power costs. Included in the 41,311 mWh were 29,850 mWh received through VEPPI, and 8,700 mWh bought by Connecticut Valley from a trash-burning plant owned by Wheelabrator Claremont Company, L.P.

     In 1999, the Company and 17 other Vermont utilities asked the PSB to make seven changes in the IPPs' contracts with the state, to reduce power costs for customers' benefit. The PSB opened an investigation. Three companies later dropped out of the case, and Green Mountain Power ("GMP") was forced out due to a previous no-litigation agreement with several IPP owners.

     Legal proceedings and negotiations continued until early 2002, when a settlement was filed with the PSB. The Company also agreed to jointly support efforts before the Vermont Legislature, resulting in the enactment of legislation to approve the use of securitization to buy down some of the IPPs' purchasing agent contracts. The Company believes that these efforts create the potential for more savings.

     After a series of hearings, in which non-petitioning utilities sought some of the settlement's benefits, a Hearing Officer issued a Proposal for Decision. It would require proportional sharing of the cost savings among all Vermont electric utilities, and reimbursement of litigation costs by the non-petitioning companies. In January 2003, the Company, other petitioning utilities, the DPS and certain non-petitioning utility parties filed an agreement, making minor changes to the proposed decision. On January 15, 2003, the PSB issued a final order approving the settlement. The PSB order required that the parties make certain compliance filings, including final dispatch agreements for the Ryegate and Sheldon Springs facilities, and utility specific plans for the distribution of savings credits to customers. The PSB is reviewing the compliance filings. Based on the settlement, nominal cost savings to all Vermont utilities are estimated between $8 and $9 million between 2004 and 2014. The savings will not begin until a certificate of consent is issued by the IPPs indicating that all conditions required under the settlement have been satisfied. At this time, the Company cannot predict when the certificate will be issued.

     In the first quarter of 2003, the Company received approximately $0.3 million in reimbursements of legal expenses from the non-petitioning companies. See Note 2, Regulatory Accounting, for additional information.

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     The following table represents a reconciliation of net income to net income available for common stock and the average common shares outstanding basic to diluted (dollars in thousands):

     The changes in the components of other comprehensive income/(loss) net of income tax effects, as shown in the Condensed Consolidated Financial Statements are as follows (dollars in thousands):

Central Vermont Public Service Corporation ("CV"), which engages in the purchase, production, transmission, distribution and sale of electricity in Vermont. Custom is included with CV in the table below.

Connecticut Valley Electric Company Inc. ("CVEC"), which distributes and sells electricity in parts of New Hampshire. CVEC, while managed on an integrated basis with CV, is presented separately because of its separate and distinct regulatory jurisdiction.

Catamount Energy Corporation ("Catamount"), which invests in non-regulated, energy generation projects in the United States and Western Europe.

All Other, which includes operating segments below the quantitative threshold for separate disclosure. These operating segments include 1) Eversant Corporation ("Eversant"), which engages in the sale or rental of electric water heaters through a subsidiary, SmartEnergy Water Heating Services, Inc., to customers in Vermont and New Hampshire. Eversant was reported separately as of December 31, 2002; 2) 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 and 3) Catamount Resources Corporation, which was formed for the purpose of holding the Company's subsidiaries that invest in non-regulated business opportunities.

     The accounting policies of the operating segments are the same as those described in the summary of significant accounting policies. Intersegment revenues include sales of purchased power to CVEC and revenues for support services, including allocations of building costs for space rental, software systems and equipment, to CVEC, Catamount and Eversant.

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     The intersegment sales and services for each jurisdiction are based on actual rates or current costs. The Company evaluates performance based on stand-alone operating segment net income. Financial information by industry segment for the first quarter of 2003 and 2002 is as follows (dollars in thousands):

Item 2.  Management's Discussion and Analysis of Financial Condition and Results of Operations.

In this section we explain the general financial condition and the results of operations for Central Vermont Public Service Corporation ("the Company", "we" or "our") and its subsidiaries.

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 the liability established by the Private Securities Litigation Reform Act of 1995. Statements made that are not historical facts are forward-looking and, accordingly, involve estimates, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Actual results will depend, among other things, upon the actions of regulators, the pending sale of our wholly owned subsidiary, Connecticut Valley Electric Company ("Connecticut Valley"), performance of the Vermont Yankee nuclear power plant, effects of and changes in weather and economic conditions, volatility in wholesale electric markets, our ability to maintain our current credit ratings and performance of our non-regulated businesses. These and other risk factors are deta iled in our annual report filed on Form 10-K as well as interim reports filed with the Securities and Exchange Commission. We cannot predict the outcome of any of these matters; accordingly, there can be no assurance that such indicated results will be realized. Readers are cautioned not to place undue reliance on these forward-looking statements that speak only as of the date of this report. We do not undertake any obligation to publicly release any revision to these forward-looking statements to reflect events or circumstances after the date of this report.

Preparation of our financial statements in accordance with accounting principles generally accepted in the United States of America ("GAAP") requires us to make estimates and assumptions that affect reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities, and revenues and expenses. The following is a discussion of certain of our most critical accounting policies. Also see Note 1 to the Consolidated Financial Statements and Critical Accounting Policies included in our annual report filed on Form 10-K.

Regulation  The Company is subject to regulation by the Vermont Public Service Board ("PSB"), the New Hampshire Public Utilities Commission ("NHPUC") and the Federal Energy Regulatory Commission ("FERC"), with respect to rates charged for service, accounting and other matters pertaining to regulated operations. As such, the Company currently prepares its financial statements in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71, Accounting for the Effects of Certain Types of Regulation ("SFAS No. 71"), for its regulated Vermont service territory, FERC-regulated wholesale business and Connecticut Valley's New Hampshire service territory. We periodically review these criteria to ensure the continuing application of SFAS No. 71 is appropriate. Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, we believe future recovery of our regulatory assets in the State of Vermont and the State of New Hampshi re for the Company's retail and wholesale businesses is probable.

     In the event that we determine the Company no longer meets the criteria under SFAS No. 71 the accounting impact would be an extraordinary charge to operations of approximately $44.2 million on a pre-tax basis as of March 31, 2003, assuming that no stranded cost recovery would be allowed through a rate mechanism.

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.

     The market value of pension plan assets has been affected by sharp declines in the capital markets. As a result, we anticipate increases in pension expense for 2003 of $1.7 million. Pension cost and cash funding requirements are expected to increase in future years and could become even more material without a significant recovery in the capital markets. As of March 31, 2003, the market value of pension plan trust assets was $53.1 million, including $33.5 million in marketable equity securities.

     We also anticipate increases in postretirement expense for 2003 of $0.6 million. The increase is primarily driven by higher than expected medical claims experience.

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     The Company reported consolidated earnings of $5 million, or 39 cents per diluted share of common stock, for the first quarter of 2003 compared to earnings of $4.8 million, or 37 cents per diluted share of common stock, for first quarter of 2002. Higher first quarter 2003 earnings compared to the same period in 2002 resulted from the following:

     Retail sales revenue increased by $2.8 million, or 4 percent, primarily due to a 2.9 percent increase in retail mWh resulting from colder winter months in 2003. Higher retail sales revenue was partially offset by increased power costs of about $0.9 million to serve the additional load.

     Net power costs, excluding the impact of higher retail sales, increased approximately $0.7 million, primarily due to higher Vermont Yankee costs under a purchased power agreement that became effective after the July 2002 sale of the plant. Offsetting these higher costs were higher resale sales due to higher wholesale market prices in 2003.

     Other operating expenses increased $0.3 million primarily due to employee-related expenses such as medical and pension benefits, partially offset by lower service restoration costs in 2003 compared to the first quarter of 2002, and internal cost-cutting efforts.

     Catamount incurred a loss of $0.1 million in 2003 compared to earnings of $0.5 million for the same period, primarily related to lower equity earnings and administrative fee revenue from certain of its investments, two of which were sold in the fourth quarter of 2002.

     Eversant recorded earnings of $0.1 million in 2003 compared to a loss of $0.6 million in 2002, due to costs incurred in 2002 from discontinuing efforts to pursue certain non-regulated businesses.

     The year over year variances are explained in more detail in the following Results of Operations.

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Operating Revenues and Megawatt-hour ("mWh") Sales Revenues from operations and related mWh sales for the first quarter of 2003 and 2002 are summarized below:

Operating revenues increased $5.1 million for the first quarter of 2003 compared to the same period in 2002 due to the following factors:

• $2.8 million increase in retail and firm sales revenue resulting from a 2.9 percent increase in retail and firm mWh sales due to colder winter months in 2003 compared to 2002
• $2.2 million increase in other resale sales primarily related to higher market prices in New England
• $0.1 million increase in other revenues related to pole attachment revenue and other miscellaneous service revenue

Net Purchased Power and Production Fuel Costs Cost components of net purchased power and production fuel for the first quarter of 2003 and 2002 are summarized in the following table (dollars in thousands):

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Net purchased power and production fuel costs increased $1.6 million for the first quarter of 2003 compared to the same period in 2002 due to the following factors:

• $2.9 million increase in purchased power costs related to 1) higher retail mWh sales, 2) higher Vermont Yankee costs under a purchased power agreement that became effective after the July 2002 sale of the plant, 3) a $0.4 million payment for an outstanding dispute related to Merrimack which was reimbursed in April 2003, 4) higher market prices in New England for short-term purchases, offset by 5) the favorable impact of lower hydro output from Independent Power Producers
• $0.8 million increase in production fuel costs due to higher output from Wyman and McNeil and a higher energy rate from Wyman
• $2.2 million increase in other resale sales primarily related to higher market prices in New England

Other Operating Costs Other major elements of the Condensed Consolidated Statement of Income for the first quarter of 2003 compared to the same period in 2002 are discussed below.

Production and transmission  The $1.1 million increase is primarily due to an increase in production fuel. See Net Purchased Power and Production Fuel Cost above for additional information.

Other operation The $2 million increase is primarily due to employee-related expenses such as medical and pension benefits.

Maintenance  The $0.7 million decrease is primarily due to lower service restoration costs in 2003 compared to 2002.

Depreciation  The $0.2 million decrease is related to lower depreciation rates resulting from a 2002 depreciation study with new rates implemented in the second quarter of 2002.

Equity in earnings of affiliates The $0.2 million decrease is primarily a result of the Vermont Yankee sale.

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

     Eversant losses in 2002 resulted from discontinuing the pursuit of non-regulated business opportunities. Catamount net revenues and expenses decreased $0.4 million related to lower Catamount equity earnings and administrative fee revenue in 2003, resulting from the sale of two investments in the fourth quarter of 2002.

Interest on long-term debt  The $0.3 million decrease is primarily related to lower principal balances due to the reduction of Catamount's outstanding revolver balance and lower utility debt.

Other interest expense The $0.1 million decrease is primarily due to refinancing utility letters of credit.

Income taxes Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences. Income taxes increased in the first quarter of 2003 compared to 2002, due to changes in permanent differences for the periods and an increase in Catamount's valuation allowance.

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Cash Dividend Declared  Preferred stock dividends decreased by $0.1 million in the first quarter of 2003 compared to 2002, related to lower outstanding preferred stock balances. Common stock dividends increased by $5.2 million in the first quarter of 2003 compared to 2002 due to timing of dividend declarations. The quarterly payment schedule remains unchanged.

Sources of Energy We purchase approximately 90 percent of our power under several contracts of varying duration. Our purchased power portfolio includes a mix of base load and schedulable resources and wholly owned resources to help cover peak load periods.

Jointly owned units Our joint-ownership interests include 1.7303 percent in Unit #3 of the Millstone Nuclear Power Station, 20 percent in Joseph C. McNeil, a 53 MW wood-, gas- and oil-fired unit, and 1.78 percent joint-ownership in Wyman #4, a 619 MW oil-fired unit.

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

     In January 2003, the Company, the State of Vermont, the Vermont Natural Resources Council and other parties reached an agreement to allow us to relicense the four dams which 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 we must begin decommissioning Peterson Dam in approximately 20 years. The agreement, however, requires PSB approval of full rate recovery related to decommissioning the Peterson Dam including full rate recovery of replacement power costs when the dam is out of service. We cannot predict the outcome of this matter.

Long Term Contracts We have long-term power contracts with Hydro-Quebec and Vermont Yankee for a combined total of approximately 85 percent of our total annual energy (mWh) purchases. See Note 3, Investments in Affiliates, for information related to the July 2002 sale of Vermont Yankee. Additionally, we are required to purchase power from various Independent Power Producers ("IPPs") under long-term contracts. See Note 6, Commitments and Contingencies, for information related to the recent settlement with the IPPs.

Other Short Term We engage in short-term purchases and sales with ISO-New England and other electric utilities, primarily in New England, in order to minimize the net costs and risk of serving our customers. Based on our long-term power forecasts, which indicate a long position, or excess energy to meet load requirements, we entered into a forward sale transaction for approximately 306,000 mWh for the period beginning February 1, 2003 and ending December 31, 2003.

Nuclear Decommissioning We are responsible for paying our 1.7303 joint-ownership percentage of Millstone Unit #3 decommissioning costs and our entitlement percentages of 2, 2 and 3.5 percent of decommissioning costs related to Maine Yankee, Connecticut Yankee and Yankee Atomic (the "Yankee companies"), respectively.

Millstone Unit #3 Our contributions to the Millstone Unit #3 Trust Fund ceased in 2001, based on the lead owners 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.

Yankee companies We are one of several sponsor companies with ownership interests in Maine Yankee, Connecticut Yankee and Yankee Atomic. These companies have been permanently shut down and are currently conducting decommissioning activities. We are responsible for paying our entitlement shares, which are equal to our ownership percentages, of decommissioning costs for all three plants.

     Each plant revises its revenue requirement forecasts on an ongoing basis, which reflect the future payments required by sponsor companies to recover estimated decommissioning and all other costs. Based on revised estimates in 2002, Maine Yankee decommissioning costs increased by $40 million and Connecticut Yankee decommissioning costs increased by $150 million, respectively, over prior estimates utilized at FERC.

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Based on a 2003-update, Yankee Atomic's decommissioning costs are now forecast at $188 million. These increases are due mainly to increases in the projected costs of spent fuel storage, security and liability and property insurance.

     Our shares of estimated revenue requirements for each plant are reflected on the Condensed Consolidated Balance Sheets as either regulatory assets or other deferred charges, depending on current recovery in existing rates, and nuclear decommissioning liabilities (current and non-current). At March 31, 2003, we had regulatory assets of approximately $8.7 million and $3.6 million related to Maine Yankee and Connecticut Yankee, respectively, and other deferred charges of approximately $3.5 million and $7.9 million related to Connecticut Yankee and Yankee Atomic, respectively. These amounts are subject to ongoing review and revisions and we will adjust the associated regulatory assets, other deferred charges and nuclear decommissioning liabilities accordingly.

     The decision to prematurely retire these nuclear power plants was based on economic analyses of the costs of operating them compared to costs of closing them and incurring replacement power costs over the remaining period of the plants' operating licenses. We believe that the premature retirements would have the effect of lowering costs to customers and based on the current regulatory process, our proportionate share of Maine Yankee's, Connecticut Yankee's and Yankee Atomic's decommissioning costs will be recovered through the regulatory process. Therefore, the ultimate resolution of the premature retirement of the three plants has not and should not have a material adverse effect on our earnings or financial condition.

Maine Yankee Costs billed by Maine Yankee, including a provision for ultimate decommissioning of the plant, are expected to be paid over the period 2003 through 2008, and are being collected from our customers through existing retail and wholesale rate tariffs.

     Maine Yankee's current billings to sponsor companies are based on their most recent rate case settlement, approved by FERC on June 1, 1999. Under the rate case settlement, Maine Yankee agreed to file with FERC a rate proceeding with an effective date for new rates of no later than January 1, 2004. We expect that Maine Yankee will seek recovery of the incremental cost increase described above in their next FERC rate filing.

Connecticut Yankee Costs billed by Connecticut Yankee, including a provision for ultimate decommissioning of the plant, are expected to be paid over the period 2003 through 2007 and are being collected from our customers through existing retail and wholesale rate tariffs.

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

Yankee Atomic Billings to sponsor companies ended in July 2000 based on Yankee Atomic's determination that it had collected sufficient funds to complete the decommissioning effort. Therefore we are not currently collecting costs in our existing rates.

     Yankee Atomic made a filing to FERC in April 2003 for rates effective June 2003 with collections from sponsor companies from June 2003 through December 2010. We expect our share of these costs to be approximately $1.1 million in 2003 and that these costs will be recoverable in future rates.

     We ended the first quarter of 2003 with cash and cash equivalents of $55 million, a decrease of $5.4 million from December 31, 2002. The decrease resulted from $12.9 million provided by operating activities, offset by $3.4 million used for investing, $14.7 million used for financing and $0.2 million used by the effect of exchange rate changes on cash. For the first quarter of 2002 we had cash and cash equivalents of $52 million, an increase of $6.5 million from the beginning of the year resulting from $14.9 million provided by operating activities, offset by $4.2 million used for investing activities and $4.2 million used for financing activities.

     Our liquidity is primarily affected by the level of cash generated from operations, reduced by the funding requirements of ongoing construction programs.  We believe that sufficient cash flow will be generated from operations to fund our anticipated needs through at least 2004. The $75 million Second Mortgage Bonds mature on

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August 1, 2004. It is currently anticipated that all or a majority of the debt will be refinanced at maturity. The type, timing and terms of future financing that we may need will depend upon our cash needs, the availability of refinancing sources and the prevailing conditions in the financial markets.

Operating Activities  Net income, depreciation, deferred income taxes and investment tax credits provided cash of $8.9 million. Working capital and other operating activities provided approximately $4 million of cash.

Investing Activities Construction and plant expenditures used cash of approximately $3.3 million and other investing activities used $0.1 million.

Financing Activities Dividends paid on common stock were $2.6 million. The pay down of capital lease obligations required $0.3 million, while the retirement of long-term debt totaled $12.6 million. Our dividend reinvestment program provided $0.5 million and sale of common stock from our Treasury shares provided $0.3 million.

Effect of Exchange Rate Changes on Cash  Net cash flow used by the effect of exchange rate changes on cash was $0.2 million, resulting from Catamount's foreign currency translations.

     Based on outstanding debt at March 31, 2003, the aggregate amount of utility long-term debt maturities and sinking fund requirements are $10.5 million and $75 million for years 2003 and 2004.  No payments are due for 2005 through 2007. It is currently anticipated that all, or a majority of, the $75 million Second Mortgage Bonds, maturing at August 1, 2004, will be refinanced at maturity. Substantially all of our Vermont utility property and plant is subject to liens under the First and Second Mortgage Bonds.

     We have an aggregate of $16.9 million of letters of credit with Citizen's Bank of Massachusetts, expiring on August 31, 2003. These letters of credit support three series of Industrial Development/Pollution Control Bonds, totaling $16.3 million. The letter of credit supporting the $5.5 million Seabrook bonds was effective on August 22, 2002. We had in place a supplemental indenture allowing the letter of credit to transfer. These letters of credit are secured by a first mortgage lien on the same collateral supporting our first mortgage bonds.

     Our long-term debt arrangements contain financial and non-financial covenants. At March 31, 2003, we were in compliance with all of our debt covenants related to various debt agreements.

     Catamount has a $25 million revolving credit/term loan facility and letters of credit, of which $8.8 million was outstanding at March 31, 2003. In early January 2003, Catamount applied $12.6 million, representing after-tax proceeds from its 2002 investment sales, against its outstanding loan balance. The facility expired on November 12, 2002 and on December 31, 2002 Catamount and its lender entered into the First Amendment to the facility that, among other things, extended the revolver facility for an additional two years. Under the two-year extension, Catamount can borrow against new operating projects subject to terms and conditions of the facility. Additionally, the outstanding revolver loans were converted to amortizing loans on a two-year term-out schedule. The interest rate is variable, prime-based. Catamount's assets secure the facility.  The aggregate amount of Catamount's long-term debt maturities, including Catamount's office building mortgage are zero and $9 million for years 2003 and 2004, respectively. Catamount's long-term debt contains financial and non-financial covenants. At March 31, 2003, Catamount was in compliance with all covenants under the revolver.

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

     Catamount invests through its wholly owned subsidiaries in non-regulated energy generation projects in the United States and Western Europe. As of March 31, 2003, through its wholly owned subsidiaries, Catamount has interests in eight operating independent power projects located in Glenns Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont; Thetford, England; Hopewell, Virginia; Thuringen, Germany and Mecklenburg-Vorpommern, Germany.

     Catamount's loss and earnings were $0.1 million and $0.5 million for the first quarter of 2003 and 2002, respectively. See Competition - Risk Factors below and Note 4, Non-Utility Investments, for more information regarding Catamount.

Eversant

     Eversant has a $1.4 million equity investment, representing a 12 percent ownership interest in The Home Service Store, Inc. ("HSS"), as of March 31, 2003.  Eversant accounts for its investment in HSS on a cost basis.

     During 2001, AgEnergy (formerly SmartEnergy Control Systems), a wholly owned subsidiary of Eversant, filed a claim in arbitration against Westfalia-Surge, the exclusive distributor that marketed and sold its SmartDrive Control product. The arbitration concerned AgEnergy's claim that Westfalia-Surge had not conducted itself in accordance with the exclusive distributorship agreement between the parties. On January 28, 2002, AgEnergy received an adverse decision related to the arbitration proceeding with Westfalia-Surge.  On November 6, 2002, Westfalia filed a Petition to Confirm the Arbitrator's Award in the United States District Court for the Western District of Wisconsin, which effectively sought to expand the Arbitrator's Award. AgEnergy submitted an answer seeking to dismiss the Petition to the extent it sought costs in excess of those established by the Arbitrator. We cannot predict the outcome of the proceeding.

     SmartEnergy Water Heating Services, Inc. ("SEWHS") had earnings of $0.1 million and $0.1 million for the first quarter of 2003 and 2002, respectively.

     Overall, Eversant incurred net earnings and losses of $0.1 million and $0.6 million for the first quarter of 2003 and 2002, respectively.

     We recognize that adequate and timely rate relief is required to maintain our financial strength, particularly since Vermont law does not allow power and fuel costs to be passed to consumers through fuel adjustment clauses. We will continue to review costs and request rate increases when warranted. In May 2002, we announced planned cost-cutting efforts and our intent to refrain from changing rates before 2006 absent unforeseen developments.

     Our current rates became effective with bills rendered July 1, 2001. These rates are based on our June 26, 2001 approved rate case settlement which is described in more detail in Note 5, Retail Rates. In accordance with the PSB's Order approving the sale of the Vermont Yankee assets, on April 15, 2003, we filed Cost of Service Studies for rate years 2003 and 2004 to determine whether a rate decrease is appropriate in either year. We cannot predict whether the PSB will open a rate investigation based upon the Cost of Service Studies, or if opened, whether an investigation would result in a rate increase or decrease.

     Connecticut Valley's retail rate tariffs, approved by the New Hampshire Public Utilities Commission ("NHPUC") contain a Fuel Adjustment Clause ("FAC"), and a Purchased Power Cost Adjustment ("PPCA"). Under these clauses, Connecticut Valley recovers its estimated annual costs for purchased energy and capacity, which are reconciled when actual data is available. See Note 5, Retail Rates, for more detail related to New Hampshire retail rates.

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Connecticut Valley Sale On December 5, 2002, the Company agreed to sell Connecticut Valley's assets to Public Service Company of New Hampshire ("PSNH"). The agreement resulted from months of negotiations with the Governor's Office of Energy and Community Services, NHPUC staff, the Office of Consumer Advocate, the City of Claremont and New Hampshire Legal Assistance. The sale is intended to resolve all Connecticut Valley restructuring litigation in New Hampshire and the Company's stranded cost litigation at FERC. The sale is expected to close January 1, 2004.

     PSNH will pay book value for Connecticut Valley's franchise and assets, which approximates $9 million at December 31, 2002. PSNH will acquire Connecticut Valley's poles, wires, substations and other facilities, and several independent power obligations, including the Wheelabrator contract. PSNH will also pay the Company $21 million for stranded power costs.

     The FERC and NHPUC must approve the sale. The NHPUC must also approve the pending settlement with Wheelabrator for the sale to close.

     On January 31, 2003, Connecticut Valley, the Company, PSNH and various other parties asked the NHPUC for approval of settlements and transactions related to the sale. The parties are seeking approval to implement restructuring in Connecticut Valley's service territory after the sale is completed, resolve litigation between the NHPUC, Connecticut Valley and the Company, and complete the sale. Under our proposed schedule, an Order would be issued by the end of June 2003. We anticipate that the New Hampshire legislature will pass the necessary legislation enabling PSNH's recovery of costs for the sale; the Governor is scheduled to sign the legislation on May 20, 2003.

     The sale could result in a gain or loss and is highly dependent on power market price forecasts at the time of the sale. At this time, we cannot estimate whether the sale will result in a gain or loss.

     If the sale transaction does not close, and the FERC exit fee proceeding, described below, ends unfavorably, there would be a material adverse effect on our results of operations, financial condition and cash flows. We cannot predict the outcome of this matter.

     See Note 8, Segment Reporting, for additional information related to Connecticut Valley.

FERC Exit Fee Proceedings On February 28, 1997, the NHPUC told Connecticut Valley to stop buying power from the Company. We asked for FERC approval, in June 1997, for a transmission rate surcharge to recover stranded costs if Connecticut Valley canceled the rate schedule. In December 1997, FERC rejected the proposal, but said it would consider an exit fee if the contract was canceled. A rehearing motion was denied, so we applied for an exit fee totaling $44.9 million as of December 31, 1997.

     On April 24, 2001, a FERC Administrative Law Judge ("ALJ") issued an Initial Decision, ruling that if Connecticut Valley terminates its wholesale contract and becomes a wholesale transmission customer of the Company, Connecticut Valley must pay stranded costs to the Company. For illustration, the ALJ calculated that payment at nearly $83 million through 2016. The exit fee decreases annually if service continues, and will be recalculated if the wholesale contract ends.

     On October 29, 2002, the Company and NHPUC asked FERC to withhold its final exit fee order so we could continue negotiating a settlement. On December 5, 2002, Connecticut Valley, the Governor's office, the City of Claremont, NHPUC staff and PSNH agreed on the sale of Connecticut Valley's assets to PSNH. The agreement, described in detail above, would make the FERC decision moot.

     Absent the sale, if Connecticut Valley had to end its contract with the Company and no exit fee was approved, we would have to recognize a pre-tax loss of about $27.4 million as of Dec. 31, 2004. That is the earliest termination could occur under the rate schedule. We would also have to write-off approximately $0.6 million pre-tax of regulatory assets. The sale of Connecticut Valley to PSNH, which includes the receipt of $21 million in stranded costs, would resolve these issues. We cannot predict whether the sale will occur under these or other terms.

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Wheelabrator Power Contract Connecticut Valley purchases power from several Independent Power Producers, who own qualifying facilities as defined by the Public Utility Regulatory Policies Act of 1978. In the first quarter of 2003, Connecticut Valley bought 9,055 mWh under long-term contracts with these facilities, 96 percent from Wheelabrator Claremont Company, L.P., ("Wheelabrator") which owns a trash-burning generating facility. Connecticut Valley had filed a complaint with FERC stating its concern that Wheelabrator has not been a qualifying facility since the facility began operation. On February 11, 1998, FERC denied Connecticut Valley's request for a refund of past power costs and lower future costs. Connecticut Valley's request for a rehearing was denied. Connecticut Valley appealed to the D.C. Circuit Court of Appeals. It denied the appeal, but said Connecticut Valley could seek relief from the NHPUC. On May 12, 2000, Connecticut Valley asked the NHPUC to amend the contract to permit purchase of only net output of the facility. Connecticut Valley also sought a refund, with interest, for purchases of the difference between net and gross output.

     On March 29, 2002, the NHPUC denied Connecticut Valley's petition. The NHPUC found that its original 1983 order did not authorize sales in excess of 3.6 MW and ordered Connecticut Valley to stop any additional purchases. Wheelabrator has been making sales of up to 4.5 MW of capacity and related energy since 1987.

     On April 29, 2002, Connecticut Valley, Wheelabrator, NHPUC Staff and the Office of Consumer Advocate submitted a settlement with the NHPUC, requiring Wheelabrator to make five annual payments of $150,000 and a sixth payment of $25,000, and Connecticut Valley to make six annual payments of $10,000, to be credited to customer bills. The settlement requires NHPUC approval. It does not change the contract between Connecticut Valley and Wheelabrator.

     A hearing on the settlement was held June 7, 2002. The NHPUC issued an Order on July 5, 2002, but did not rule on the settlement. Instead, the NHPUC said it would appoint a mediator to work with all parties to see if a new settlement could be reached. The NHPUC selected a mediator and, after several mediation sessions, the mediator issued a report on December 18, 2002. The opponents still oppose the settlement.

     The NHPUC must approve the settlement for the sale of Connecticut Valley to close. Through the sale, PSNH will acquire Connecticut Valley's independent power obligations, including the Wheelabrator contract.

     The electric utility industry is undergoing a transition. Many states, including New Hampshire, have tried to create greater competition, customer choice and market influence while retaining the benefits of the regulatory system. The pace of transition slowed in 2001, due primarily to deregulation problems in California and the collapse of the wholesale market.

     There have been three unsuccessful attempts to restructure the industry in Vermont: the Governor's Working Group, which completed its work in 1998, and in two investigatory PSB dockets that have closed. At this time, we cannot determine when or if retail competition will be introduced in Vermont.

Regional Transmission Organizations  Pursuant to FERC Order No. 888 (issued April 1996) we operate our transmission system under an open-access tariff.

     In 1999, FERC began work to amend regulations and facilitate formation of regional transmission organizations ("RTO"). Late that year, FERC issued Order No. 2000 for that purpose. Since then, we have participated in numerous related proceedings. On November 22, 2002, NEPOOL notified FERC that it was withdrawing a proposal made with New York to form the Northeast RTO. NEPOOL has since suggested creation of an RTO for New England, and is expected to file for that purpose by mid-year 2003. We, along with other transmission-owning entities in New England, including VELCO, are in talks intended to create a transmission network company required under Order No. 2000. FERC issued a Standard Market Design Notice of Proposed Rulemaking ("SMD NOPR") in July 2002 to establish nation-wide rules for power markets and RTOs. After ten months of outreach and input from stakeholders, FERC issued a White Paper on April 28, 2003 to clarify its positions on the SMD NOPR. The New England RT O filing will most likely reflect some of the changes in the FERC position. The rulemaking is designed to separate governance and operation of the transmission system from generation companies and other market participants and to facilitate power markets with common rules. We cannot predict the outcome of this matter or its impact.

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Standard Market Design ("SMD") ISO-New England implemented SMD on March 1, 2003. The following is a discussion of some of the changes resulting from SMD:

• Energy pricing based in part on transmission congestion and losses experienced in each zone within the region. Previously, the costs of congestion and losses were spread across New England energy providers on a pro rata basis. Based on trials beginning in late 2002 and initial experience since March 1, congestion appears to be worst in eastern Massachusetts and southwestern Connecticut, while losses may be high in Vermont. Initially, the State of Vermont comprises a single load zone under SMD. Generators receive location-specific prices depending on where they connect with the New England electric network.
• A location-specific market allowing participants to settle transactions involving load and generation one day in advance of the real-time spot market.
• An auction-based system of Financial Transmission Rights ("FTR") to allow participants to hedge congestion risks. FTR holders are paid a share of actual congestion revenue, while auction proceeds are given to load entities that experience congestion or companies that increase the capacity of the network.

• Operating reserve requirements have also changed.
• ISO-New England has increased the financial assurance requirement for market participants, based on their credit ratings and financial conditions.
• The rules that require load-serving entities to hold rights to generating capacity based on peak demands in the region have changed in that the responsibility is now based on each entity's share of the New England peak load during the previous calendar year. In general, the region tends to experience its annual peak in summer months, while our peak tends to occur in December or January. The capacity credit received for generation has also changed to better reflect the performance of certain generators.

     The vast majority of our generating resources are located in Vermont or delivered at locations such that congestion is not expected to be significant relative to what had been our share of the region-wide congestion. Because of their magnitude, congestion and loss costs are the two types of power-related costs with the greatest potential to change the cost of service compared to the pre-SMD environment.

     In general, we own or hold entitlements to generation that can be self-scheduled in the day-ahead market. We are using that market to clear the majority of our load and generation, including generation resources that we self-schedule, with any remaining resources and residual load settling in the real-time market. The overall price level and volatility of these new markets are still not known given that SMD became operational on March 1, 2003. We will continue to use risk mitigation strategies and our largely firm-priced sources to limit risks.

     ISO-New England is also working with the region's stakeholders to propose to FERC a new cost allocation rule to determine who will pay the costs of upgrades to the regional transmission network. VELCO is planning several upgrades. Our share of the costs of any new investments will be affected by FERC cost-allocation rulings.

Asset Retirement Obligations: In August 2001, the Financial Accounting Standards Board ("FASB") approved the issuance of SFAS No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143"). This statement provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of long-lived assets and requires entities to record the fair value of a liability for an asset retirement obligation ("ARO") in the period in which it is incurred. We adopted SFAS No. 143 on January 1, 2003 as required and did not have a cumulative effect upon adoption.

We have legal retirement obligations associated with decommissioning related to our investments in nuclear plants, certain of our jointly owned generating plants and certain Catamount investments. Our regulated operations also collect removal costs in rates for certain utility plant assets that do not have associated legal asset retirement obligations. As of March 31, 2003, approximately $4.3 million related to non-legal removal costs is recorded in Accumulated Depreciation.

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Variable Interest Entities: In January 2003, the FASB issued Interpretation 46, Consolidation of Variable Interest Entities. This standard will require an enterprise that is the primary beneficiary of a variable interest entity to consolidate that entity. The Interpretation must be applied to any existing interests in variable interest entities beginning in the third quarter of 2003. We do not expect to consolidate any existing interests in unconsolidated entities pursuant to the requirements of Interpretation 46.

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                Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Utility If retail competition is implemented in Vermont or in Connecticut Valley's New Hampshire 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. We expect power distribution and transmission service to our customers to continue on an exclusive basis subject to continuing economic regulation. See Note 2, Regulatory Accounting, for more information.

Interest Rate Risk As of March 31, 2003, we have $16.3 million of Industrial Development/Pollution Control bonds outstanding, of which $10.8 million have an interest rate that floats monthly and $5.5 million floats every five years with the short-term credit markets. All other utility debt has a fixed rate. There are no interest lock or swap agreements in place. We have $50.2 million of consolidated temporary cash investments as of March 31, 2003, including $18.8 million of non-utility temporary cash investments. Interest rate changes could also impact calculations related to estimated pension and other benefit liabilities, thereby affecting pension and other benefit expenses and potentially requiring contributions to the trusts.

Equity Market Risk As of March 31, 2003, our pension trust held marketable equity securities in the amount of $33.5 million and our share of the Millstone Unit #3 decommissioning trust held marketable equity securities in the amount of $2.2 million. We also maintain a variety of insurance policies in a Rabbi Trust with a current value in the amount of $4.3 million to support various supplemental retirement and deferred compensation plans. The current values of certain of these policies are affected by changes in the equity market.

Non-Utility Catamount has refocused its efforts from being an investor in late-stage renewable energy to being primarily focused on developing, owning and operating wind energy projects.  Catamount's future success is dependent on the acceptance of wind power as an energy source by large producers, utilities, and other purchasers of electricity. Historically, the wind energy industry had a reputation for numerous problems relating to the failure of many wind-power generating facilities developed in the early 1980s to perform acceptably. In addition, many potential customers believe that wind energy is an unpredictable and inconsistent resource, is uneconomic compared to other sources of power and does not produce stable voltage and frequency. Although Catamount believes that these concerns are adequately addressed in the near-term, there is no guarantee of wind power acceptance by potential customers as an energy source.

Interest Rate Risk Catamount has a variable rate revolving credit/term loan facility with an outstanding balance of $8.8 million at March 31, 2003. The outstanding balance is scheduled to term out towards the end of 2004 thereby reducing Catamount's exposure to interest rate risk. Catamount also maintains temporary cash investment accounts to meet its liquidity needs. At March 31, 2003, Catamount's temporary cash investments amounted to $8.3 million.

     Also see Competition - Risk Factors in our annual report on Form 10-K for the year ended December 31, 2002 for additional information related to utility and non-utility risk factors.

Item 4.    Controls and Procedures.

     The Company's management, including the President and Chief Executive Officer and Senior Vice President, Chief Financial Officer and Treasurer, have evaluated the effectiveness of the design and operation of the Company's disclosure controls and procedures, as of a date within 90 days prior to the filing date of this report. Based on such evaluation, the Company's management, including the President and Chief Executive Officer and Senior Vice President, Chief Financial Officer and Treasurer, concluded that the Company's disclosure controls and procedures are effective in ensuring that material information relating to the Company with respect to the period covered by this report was made known to them. There have been no significant changes in the Company's internal controls or in other factors that could significantly affect internal controls subsequent to evaluation.

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PART II - OTHER INFORMATION

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SIGNATURES

      Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Dated  May 9, 2003

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I, Robert H. Young, certify that:

Date: May 9, 2003

/s/ Robert H. Young        
Chief Executive Officer

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I, Jean H. Gibson, certify that:

Date: May 9, 2003

/s/ Jean H. Gibson         
Chief Financial Officer

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EXHIBIT INDEX

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