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     June 30, 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 July 31, 2003 there were outstanding 11,919,665 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
(Dollars in thousands, except per share amounts)
(unaudited)

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

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(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 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 a Vermont-based electric utility that distributes, transmits and markets electricity and invests in renewable and independent power projects. 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. See Note 6, Discontinued Operations - Connecticut Valley Sale.

     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 and is considering the transfer of its interests in Vermont Electric Power Company.

     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 second quarter and first half of 2003 are not necessarily indicative of the results that may be expected for the 12 months ended December 31, 2003. For further information, refer to the consolidated financial statements and footnotes 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 Commission f ilings.

Discontinued Operations On May 23, 2003, the New Hampshire Public Utilities Commission ("NHPUC") approved the sale of Connecticut Valley's franchise and net plant assets to Public Service Company of New Hampshire ("PSNH"). Accordingly, the Company classified certain assets and liabilities of Connecticut Valley as held for sale in the Condensed Consolidated Balance Sheets in accordance with Statement of Financial Accounting Standards ("SFAS") No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, ("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. For restatement purposes, certain of the Company's common corporate costs, which were previously allocated to Connecticut Valley, have been reallocated to reflect the sale's impact on continuing operations.

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 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.

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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"). It provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of long-lived assets and requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The Company 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 June 30, 2003, approximately $4.7 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. It requires 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.

Derivative Instruments and Hedging Activities:  In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 Derivative Instruments and Hedging Activities. This standard amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts and hedging activities under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. This statement clarifies when a contract with an initial net investment meets the characteristic of a derivative and when a derivative contains a financing component. This statement also amends the definition of an underlying to conform to the language contained in FIN No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Guarantees of Indebtedness of Others. This statement is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The Company is assessin g how this statement might impact its future results of operations, financial position and cash flows.

     The Company is regulated by the PSB, NHPUC and Federal Energy Regulatory Commission ("FERC"), with respect to rates charged for service, accounting and other matters pertaining to regulated operations. The Company 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 continuing application of SFAS No. 71 is appropriate. Based on a current evaluation of the factors and conditions expected to impact future cost recovery, Management believes future recovery of regulatory assets in Vermont and New Hampshire for its retail and wholesale businesses is probable.

     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. Regulatory assets related to Connecticut Valley are included in assets held for sale on the Condensed Consolidated Balance Sheets. 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 table that follows.

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

     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.

     All regulatory approvals were granted on terms acceptable to the parties to the transaction. Certain intervener parties appealed the PSB approval to the Vermont Supreme Court. On July 25, 2003, the Court upheld the sale, rejecting the intervener's appeal.

     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 receives 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.

     Although the sale closed on July 31, 2002, the final calculation of the distributions is not complete. Cash distributions related to the sale will be received in 2003. The Company expects either a small gain or loss related to this transaction.

     Vermont Yankee's revenues shown above include sales to the Company of $17.1 million for the second quarter and $33.8 million for the first half of 2003, compared to $16.3 and $28.9 million for the comparable periods in 2002. 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.

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

     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) of $2.5 million for the second quarter and $5.7 million for the first half of 2003, compared to $3.2 and $6.3 million for the comparable periods in 2002.

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     Catamount invests through its wholly owned subsidiaries in non-regulated energy generation projects in the United States and Western Europe. As of June 30, 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 earnings were $0.2 and $0.5 million for the second quarter of 2003 and 2002, respectively, and $0.1 and $0.9 million for the first half of 2003 and 2002, respectively.   Information regarding certain of Catamount's investments follows.

Fibrothetford Limited Continuing equity losses have been applied as a reduction to Catamount's note receivable balance from Fibrothetford. Catamount reserved $0.5 and $0.9 million of note receivable interest income for the second quarter and first half of 2003, and $0.4 and $0.7 million for the comparable periods in 2002.

     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. In July 2003, the buyer suspended the sale. Catamount can not predict whether the sale will ultimately be consummated.

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 by the end of 2003. Management does not believe this will have a material impact on Catamount.

Sweetwater On June 30, 2003, Catamount entered into an equity commitment for up to a $10.1 million equity investment in the 37.5-MW wind farm in Nolan County, Texas known as Sweetwater I. Providing conditions to the equity commitment are satisfied, Catamount will become an equity partner in December 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.

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 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. 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.

     In accordance with the PSB's approval of the Vermont Yankee sale, 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. On July 11, 2003, the Company and DPS signed a Memorandum of Understanding ("Memorandum") regarding the Company's rates and allowed return on equity through the end of 2005, subject to a prior rate change.  The Memorandum is subject to approval by the PSB, and provides, among other things, the following:

• Rate Stability - The DPS and the Company agreed that a change in the Company's rates in 2003 and 2004 is not warranted as a result of the Vermont Yankee sale. The Company agreed not to file for a rate increase for rates effective prior to January 1, 2005, subject to the Company's need for an emergency rate increase under certain circumstances.
• Earnings Cap - The Memorandum requires the Company to reduce its current 11.00 percent allowed return on equity to 10.50 percent July 1, 2003. If the Company earns more than 10.75 percent in 2003, or 10.50 percent in either 2004 or 2005, any excess earnings shall be applied to reduce deferred debits as approved by the PSB. The Memorandum requires the Company to file a report detailing its "core return on equity" for 2003 and 2004 on March 1 of each of the following years.

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• Redesign of Rates - Within 60 days of the PSB's approval of the Memorandum, the Company shall file with the PSB a fully allocated cost of service study and a proposed rate redesign.
• Alternative Regulation Plan - The Company and the DPS have agreed to work cooperatively to develop and propose an alternative regulation plan by March 31, 2004. The Memorandum does not compel a filing of a plan absent agreement by the Company.

     In July 2003, the PSB opened a Docket to review the Memorandum; a prehearing conference is scheduled for September 2003. The Company cannot predict whether the PSB will approve the Memorandum.

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 request for an Interim PPCA to reduce a potential overcollection during the remainder of 2003. As a result, Connecticut Valley's rates decreased 6.3 percent beginning May 1, 2003, and revenues are expected to decrease $0.8 million for the year. These rates are expected to remain in effect until completion of the sale. See Note 6, Discontinued Operations - Connecticut Valley Sale below.

     On December 5, 2002, the Company agreed to sell Connecticut Valley's franchise and net plant 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 to Connecticut Valley for Connecticut Valley's franchise, net plant assets and related items, the book value of the assets, which approximates $9 million at June 30, 2003, plus $21 million, plus certain other adjustments as provided in the agreement. PSNH will acquire Connecticut Valley's poles, wires, substations and other facilities, and several independent power obligations, including the Wheelabrator contract. The $21 million payment will enable Connecticut Valley and the Company to terminate their wholesale power contract.

     On January 31, 2003, Connecticut Valley, the Company, PSNH and various other parties asked the NHPUC to approve settlements and transactions related to the sale. The parties sought 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.

     On May 23, 2003, following technical hearings on May 15, 2003, the NHPUC approved the sale without conditions. In its order the NHPUC also approved the settlement with Wheelabrator. On July 22, 2003, the Company and PSNH filed an application with FERC for approval of the sale of facilities under its jurisdiction. The Company and Connecticut Valley filed an Offer of Settlement with FERC the same day to permit termination of the wholesale power contract and related exit fee proceedings upon completion of the sale.

     In accordance with SFAS No. 144, in the second quarter of 2003, the Company classified the assets and liabilities of Connecticut Valley as held for sale in the Condensed Consolidated Balance Sheets. 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. For restatement purposes, certain of the Company's common corporate costs, which were previously allocated to Connecticut Valley, have been reallocated to reflect the impact of the sale on continuing operations.

     Whether the sale results in a gain or loss 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.

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

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

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

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. The ALJ calculated the stranded cost 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. The Connecticut Valley sale, described in detail above, would make the FERC decision moot.

     On July 22, 2003, the Company and Connecticut Valley filed an Offer of Settlement with FERC to permit termination of the wholesale power contract and related exit fee proceedings upon completion of the sale.

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     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 December 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, would resolve these issues. Management believes that the January 1, 2004 closing for the sale is probable.

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 half of 2003, Connecticut Valley bought 18,696 mWh under long-term contracts with these facilities, 93 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 it 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 purc hase 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 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's May 23, 2003 approval of the sale included approval of the settlement with Wheelabrator. 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 owner's representation to various regulatory bodies that the Trust Fund, for its share of the plant, exceeded the Nuclear Regulatory Commission's minimum calculation required. The Company could choose to renew funding at its 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 the Yankee companies. These companies have permanently shut down generating activities 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 company regularly revises its revenue requirement forecasts, 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 over prior estimates utilized at FERC. Based on a 2003 update, Yankee Atomic's decommissioning costs are now forecast at an additional $188 million. These increases are due mainly to increases in projected costs of spent fuel storage, security and liability and property insurance.

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     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 June 30, 2003, the Company had regulatory assets of about $8.4 and $3.4 million related to Maine Yankee and Connecticut Yankee, respectively, and other deferred charges of about $3.5 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 operating costs 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 lower costs to customers, and based on the current regulatory process, its proportionate shares of Maine Yankee, Connecticut Yankee and Yankee Atomic 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 decommissioning, are expected to be paid between 2003 and 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 settlement, Maine Yankee agreed to file a FERC 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 decommissioning, are expected to be paid between 2003 and 2007, and are being collected from the Company's customers through existing retail and wholesale rate tariffs.

     Connecticut Yankee is currently involved in a contract dispute with Bechtel Power Corporation ("Bechtel"). The dispute is in regards to Connecticut Yankee's concern with Bechtel's performance. Bechtel had been Connecticut Yankee's decommissioning contractor. On June 13, 2003, following unsuccessful attempts to reach a mutually acceptable settlement, Connecticut Yankee notified Bechtel of its plans to terminate the contract for various contract defaults including its "refusal to provide a Project Completion Schedule and to perform the remaining decommissioning tasks." Under the contract, Bechtel had 30 days to cure its defaults before the termination became effective; it failed to do so. As a result, on July 14, 2003, Connecticut Yankee became the general contractor for the decommissioning.

     Bechtel responded to the notice of termination by filing a complaint for breach of contract, misrepresentation, and bad faith in Middlesex County Superior Court on June 23, 2003. Bechtel charges that Connecticut Yankee's mismanagement of the decommissioning effort and undisclosed problems over years of prior operations, delayed the project by three years and increased costs to Bechtel.

     Connecticut Yankee is expected to bring a lawsuit against Bechtel. This is a commercial contract dispute; Bechtel's defaults are not related to safety, security or workmanship issues. Connecticut Yankee estimates that as a result of Bechtel's poor contract performance, the project is more than 2 1/2 years behind schedule.

     Connecticut Yankee is required to file an updated cost of service with FERC by July 1, 2004. The Company expects Connecticut Yankee to request recovery from its sponsor companies of the $150 million in increased decommissioning costs. The Company also expects the same request regarding the excess project completion costs resulting from the Bechtel contract termination, pending recovery of those costs from Bechtel, and, if necessary, American Home Insurance Company. It provided a $36 million Performance Bond to Connecticut Yankee. Management cannot predict the outcome of this matter.

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 related to the increased costs described above. FERC approved the resumption of billings starting June 2003 subject to refund. 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.

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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. 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.

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. 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 June 30, 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. For the first half of 2003, the Company received 98,954 mWh, which accounts for 7.4 percent of the total mWh purchased and 13.5 percent of purchased power costs. Included in the 98,954 mWh were 72,841 mWh received through VEPPI, and 17,363 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 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

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decision. On January 15, 2003, the PSB issued a final order approving the settlement. The PSB required that the parties make certain compliance filings, including final dispatch agreements for the Ryegate and Sheldon Springs facilities, and utility-specific plans for distributing savings to customers. By Orders dated June 9 and July 10, 2003, the PSB approved the Company's compliance filings and the Ryegate dispatch agreement. The petitioning utilities, VEPPI and Missisquoi Associates are finalizing a proposed Sheldon Springs dispatch agreement. Based on the settlement, nominal cost savings to all Vermont utilities are estimated between $8 million and $9 million between 2004 and 2014, exclusive of savings that might result from implementation of IPP contract buy downs through securitization. The Company should receive approximately 40 percent of the power savings credits made available under the settlement. Under the settlement, the power cost savings could not begin until a certificate o f consent was issued by the IPPs indicating that all conditions required under the settlement were satisfied. In June 2003, the IPPs issued the required certificates, and VEPPI began passing along power cost savings to all Vermont utilities including the Company. The Company cannot predict when the final Sheldon Springs dispatch agreement will become effective although it is expected to occur before the end of 2003.

    See Note 2, Regulatory Accounting, for additional information.

     The following table represents a reconciliation of net income from continuing and discontinued operations 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)

     The Company's reportable operating segments include:

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

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

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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.  All prior period amounts have been restated to reflect this new classification; 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 to hold 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 revenues for support services, including allocations of building costs for space rental, software systems and equipment, to Catamount and Eversant. Due to the pending sale of Connecticut Valley's franchise and net plant assets as described in Note 6, Discontinued Operations - Connecticut Valley, results of operations for Connecticut Valley are reported as discontinued operations in the segment table below.

     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 second quarter of 2003 and 2002 and the first six months of 2003 and 2002 is as follows (dollars in thousands):

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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 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 some 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 regulated by the Vermont Public Service Board ("PSB"), the New Hampshire Public Utilities Commission ("NHPUC") and Federal Energy Regulatory Commission ("FERC"), with respect to rates charged for service, accounting and other matters pertaining to regulated operations. The Company 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 continuing application of SFAS No. 71 is appropriate. Based on a current evaluation of the various factors and conditions expected to impact future cost recovery, we believe future recovery of our regulatory assets in Vermont and New Hampshire 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 about $42.8 million on a pre-tax basis as of June 30, 2003, assuming that no stranded cost recovery would be allowed through a rate mechanism.

Discontinued Operations On May 23, 2003, the NHPUC approved the sale of Connecticut Valley's franchise and net plant assets to Public Service Company of New Hampshire ("PSNH"). Accordingly, the Company classified the assets and liabilities of Connecticut Valley as held for sale in the Condensed Consolidated Balance Sheets in accordance with Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, ("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. For restatement purposes, certain of the Company's common corporate costs, which were previously allocated to Connecticut Valley, have been reallocated to reflect the sale's impact on continuing operations.

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. We anticipate increases in pension expense of $1.7 million for 2003. Pension costs 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 June 30, 2003, the market value of pension plan trust assets was $58.6 million, including $38.7 million in marketable equity securities, compared to pension plan trust assets of $55.9 million at December 31, 2002.

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

     The Company reported consolidated second quarter earnings of $5.1 million, or 40 cents per diluted share of common stock, a 10-cent increase from a year ago. Second quarter 2002 earnings totaled $4 million, or 30 cents per diluted share of common stock.

     For the first six months of 2003, the Company reported earnings of $10.1 million, or 79 cents per diluted share of common stock, a 12-cent increase from a year ago. First six months of 2002 earnings totaled $8.8 million, or 67 cents per diluted share of common stock.

     The results of operations related to the Company's wholly owned subsidiary, Connecticut Valley, have been reported separately as discontinued operations. The sale of Connecticut Valley's franchise and net plant assets to PSNH is expected to close January 1, 2004. In the second quarter and first six months of 2003, discontinued operations contributed 2 and 6 cents to consolidated earnings per share (basic and diluted) compared to 3 and 6 cents for the comparable periods in 2002.

     The following tables provide a reconciliation of 2003 and 2002 diluted earnings per share.

1. Lower life insurance expense due to market fluctuations, lower ISO-New England transmission congestion charges, lower storm-related restoration costs in 2003 compared to 2002, internal cost cutting, lower employee medical costs and additional reserve for bad debt in 2002, offset by higher employee-related costs such as pension.