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, 2002    

|     |      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, 2002 there were outstanding 11,684,101 shares of Common Stock, $6 Par Value.

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Form 10-Q - 2002

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

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)

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

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     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 the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the quarter and six-months ended June 30, 2002 are not necessarily indicative of the results that may be expected for the twelve months ending December 31, 2002. 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, 2001.

Reclassifications: The Company will record reclassifications to the financial statements of the prior year when considered necessary or to conform to current year presentation. In the fourth quarter of 2001, Catamount Energy Corporation recorded $11.0 million of long-term non-utility investments as current. See Note 3 of Notes to Consolidated Financial Statements in the Company's 2001 Annual Report on Form 10-K, for additional information.

     Under Statement of Accounting Standards No. 71 ("SFAS No. 71"), Accounting for Certain Types of Regulation, the Company accounts for certain transactions in accordance with permitted regulatory treatment. As such, regulators may permit incurred costs, typically treated as expense 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, the Company would be required to write off related regulatory assets, certain other deferred charges and regulatory liabilities as summarized in the following table:

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     In accordance with ratemaking treatment, the incremental costs attributable to replacement energy and maintenance costs, incurred during regular nuclear refueling outages, are deferred and amortized ratably to expense until the next regularly scheduled refueling outage, which is typically over 18 months. During the first six months of 2001, Vermont Yankee and Millstone Unit #3 had scheduled refueling outages. The next scheduled refueling outages are October 2002 and September 2002 for Vermont Yankee and Millstone Unit #3, respectively. Also see Note 4, Vermont Yankee - Sale.

     In the second quarter of 2002, the Company deferred approximately $3.8 million related to the incremental capacity and replacement energy costs resulting from a May 2002 Vermont Yankee mid-cycle outage to repair defective fuel rods. Based on an approved Accounting Order from the Vermont Public Service Board ("PSB"), the Company has been authorized to defer these costs for recovery in future rates and as such the deferred costs are included in Other deferred charges on the Consolidated Balance Sheet. See Note 4, Vermont Yankee - Operations for additional information related to the Accounting Order.

     The Company records as regulatory liabilities, those costs that have been recovered by the Company but have not yet been included in rates. At June 30, 2002, the Company had approximately $2.5 million in regulatory liabilities, which includes $1.6 million related to the Hydro-Quebec Ice Storm settlement explained in more detail in Note 5 - Retail Rates. The regulatory liabilities are included in Other deferred credits on the Consolidated Balance Sheets.

     The Company accounts for its investments in Vermont Yankee Nuclear Power Corporation ("Vermont Yankee") and Vermont Electric Power Company using the equity method. Summarized financial information is as follows (dollars in thousands):

     In the first quarter of 2002, the Company's ownership percentage of Vermont Yankee changed from 31.3% to 33.23% related to the repurchase of shares held by minority owners of the plant. On July 31, 2002, the Vermont Yankee plant was sold to Entergy, however the Company continues to have a 33.23% equity interest in the remaining corporation, which will administer the long term power purchase contract between Entergy and the former utility owners of the Vermont Yankee plant. The Company's entitlement percentage of Vermont Yankee's output continues to be 35% with two remaining secondary purchasers receiving a small percentage of the Company's entitlement as well. See Note 4, Vermont Yankee - Sale, for more detail.

     The Company owns 56.8% of VELCO's outstanding common stock, however, the 1985 Four-Party Agreement (as amended) under which VELCO operates, effectively restricts the Company's control of VELCO. The Company also owns 46.6% of VELCO's outstanding preferred stock, $100 par value.

     On June 15, 2002, the Company and Green Mountain Power Corporation ("GMP") filed a joint application to the Federal Energy Regulatory Commission ("FERC") requesting authorization for each to purchase certain shares of non-voting, $100 par value, Class C common stock issued by VELCO. Under the proposed transaction, VELCO

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will issue up to 16,170 shares of Class C common stock to provide working capital, maintain a debt-to-equity ratio within the guidelines of VELCO's Article of Association, and adjust total equity ownership. On July 15, 2002, the FERC approved the transaction. The Company expects to acquire shares of VELCO's common stock in the third quarter of 2002, however the Company's control of VELCO will continue to be restricted.

     On August 15, 2001, Vermont Yankee announced that a sales agreement had been reached with Entergy Corporation ("Entergy") for $180 million, representing $145 million for the plant and related assets and $35 million for nuclear fuel. Entergy will also assume decommissioning liability for the plant and its decommissioning trust fund. The agreement includes a purchase power contract with prices that generally range from 3.9 cents to 4.5 cents per kilowatt-hour subject to a "low-market adjuster" that protects the current Vermont Yankee owner-utilities, including the Company and its power consumers, in the event power market prices drop significantly. On September 27, 2001, the Company filed testimony with the PSB in support of the sale. In an order entered October 26, 2001, the PSB granted intervention to several parties that the Company did not oppose, and established a schedule that provided for discovery, hearings and final briefing by April 29, 2002. Certain of the i ntervenors were secondary purchasers of Vermont Yankee power, which were seeking adjustments in their power purchase contracts, and stockholders of Vermont Yankee, which were asserting dissenters' rights. On January 16, 2002, Vermont Yankee announced that it had reached an agreement with the secondary purchasers and had repurchased the shares held by the minority stockholders; these parties requested to withdraw from the PSB proceeding. On January 1, 2002, as a result of the repurchased shares, the Company's ownership percentage of Vermont Yankee changed from 31.3% to 33.23%.

     Following hearings on February 4 - 8 and 14 - 15, 2002, the Company, GMP, Vermont Yankee and Entergy filed rebuttal testimony. On March 6, 2002, the Company, GMP, Vermont Yankee, Entergy and the Department of Public Service ("DPS") filed a joint Memorandum of Understanding ("MOU") that resolved all issues raised by the DPS earlier in the proceeding and in which the MOU parties recommend approval of the sale in accordance with the terms of the MOU. The intervenors did not join in the MOU. During April 2002, the Board held hearings on the rebuttal testimony of all parties as well as the MOU. All parties filed Initial Briefs on May 7, 2002, with Reply Briefs filed on May 14, 2002.

     On May 17, 2002, the Nuclear Regulatory Commission approved the transfer of the Vermont Yankee operating license to Entergy. The FERC approved the sale on February 1, 2002.

     On June 13, 2002, the PSB issued an Order approving the Vermont Yankee sale to Entergy, along with the associated power purchase agreement between the current owners and Entergy. In approving the transactions, the PSB largely accepted the terms of the MOU reached between the current owners, Entergy and the DPS, however the PSB set several conditions, including:

• Requiring that any money remaining in the decommissioning fund following completion of decommissioning be returned to consumers;
• Requiring that the Company and GMP submit plans for using their share of any excess remaining in the decommissioning fund, toward the development and use of renewable resources for Vermont;
• Significant financial guarantees and corporate commitments from Entergy's parent corporation, ensuring the reliability of its subsidiaries' commitments;
• Requiring the Company to file an updated cost-of-service and appropriate additional information as necessary in April 2003 to determine whether a rate decrease is appropriate in 2003 or 2004; and
• Prohibiting Entergy from operating Vermont Yankee after March 31, 2012 without prior approval of the PSB.

     On June 21, 2002, Entergy filed a Motion to Alter or Amend the PSB's June 13 Order to accept the agreement between the Vermont Yankee owners and the DPS as written and allow the 50-50 sharing with ratepayers of any excess remaining in Vermont Yankee's decommissioning trust fund after the decommissioning is completed after 2022. On July 1, 2002, the DPS issued a response to the PSB regarding Entergy's Motion requesting that the PSB reconsider its ruling of June 13, 2002 and recommended that any excess decommissioning funds be split between ratepayers and Entergy. On July 11, 2002, the PSB rendered a decision on Entergy's Motion in which the PSB confirmed its June 13, 2002 Order.

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     On July 18, 2002, Entergy announced that it would not accept the condition included by the PSB in its June 13, 2002 Order and its July 11, 2002 ruling confirming that Order. Instead Entergy said it would examine ways to reengineer the terms of the sale to produce a mutually acceptable agreement within the 12 days left to close the sale.

     On July 22, 2002, Entergy and the utility owners of Vermont Yankee reached agreements that would allow the sale to close before July 31, 2002 when the purchase agreement ends. Under the terms of the agreements, Vermont ratepayers will receive 100% of the Vermont utilities' share of any surplus remaining in the decommissioning fund when the plant is decommissioned. The non-Vermont owners, representing 45% ownership of the plant, will restore the substance of the original agreement by assigning 100% of their excess decommissioning funds to Entergy. The Company and GMP agreed to contribute $1.5 million in stockholder funds to the non-Vermont utility owners of the plant to provide parity for assigning their share of the decommissioning fund to Entergy. The Company's share is approximately $950,000 pre-tax and would be expensed upon the closing of the sale.

     On July 23, 2002, the New England Coalition on Nuclear Pollution ("NECNP") and the Citizens Awareness Network ("CAN") filed a Petition for Temporary Restraining Order and Preliminary Injunction regarding the July 22, 2002 proposed sale terms between Entergy, the Vermont Yankee owners, GMP and the Company. On July 26, 2002, the PSB denied the request for Temporary Restraining Order and found that the July 22, 2002 agreements between Entergy and the utility owners of Vermont Yankee met all of the conditions the PSB placed on its earlier approval of the sale.

     On July 29, 2002, NECNP and CAN filed a Complaint with the FERC, seeking a "fast track" hearing to delay the sale. The FERC has provided notice of the complaint, requesting that answers, comments, interventions or protests must be filed by August 19, 2002.

     On July 29, 2002, NECNP and CAN filed with the PSB Motions to Alter or Amend, Enter Final Judgement, and Stay pending Appeal. Additional petitions were filed by intervenors and others with the regulatory commissions of New Hampshire, Massachusetts and Maine. On July 30, 2002, the PSB and the Maine and Massachusetts commissions issued rulings approving the sale and denying the requests for stays. On July 31, 2002, the New Hampshire commission issued its ruling approving the sale.

     The Securities and Exchange Commission approved the sale on July 30, 2002.

     On July 31, 2002, Vermont Yankee completed the sale of its assets to Entergy. The Company continues to have a 33.23% equity interest in Vermont Yankee Nuclear Power Corporation that will continue as a Vermont-based entity that will administer the purchase power contracts among the former utility owners and Entergy. The Company will continue to receive its 35% entitlement of Vermont Yankee output under the purchase power agreement described above. Additionally, two remaining secondary purchasers will continue receiving a small percentage of the Company's entitlement.

     The Vermont Yankee nuclear power plant, which provides more than one-third of the Company's power supply, had a scheduled refueling outage in late April - May 2001; that outage was 11 days shorter than budgeted. The previous refueling outage began in late October 1999 and the plant returned to service in early December 1999. The 1998 refueling outage (March 21-June 3) extended 26 days beyond the scheduled 49 days. The next scheduled refueling outage is October 2002.

     In May 2002, Vermont Yankee had a mid-cycle outage, starting May 11 and ending May 23, in order to repair defective fuel rods. The Company requested and received PSB approval of an Accounting Order to defer incremental capacity and replacement energy costs related to the mid-cycle outage. In the second quarter of 2002, the Company deferred approximately $3.8 million related to the incremental capacity and replacement energy costs resulting from the May 2002 Vermont Yankee mid-cycle outage.

     The Company recognizes that adequate and timely rate relief is necessary if it is to maintain its financial strength, particularly since Vermont regulatory rules do not allow for changes in purchased power and fuel costs to be automatically passed on to consumers through rate adjustment clauses. The Company intends to continue its practice of periodically reviewing costs and requesting rate increases when warranted.

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     2000 Retail Rate Case: In an effort to mitigate eroding earnings and cash flow prospects in the future, due mainly to under-recovery of power costs, on November 9, 2000, the Company filed with the PSB a request for a 7.6% rate increase ($19.0 million of annualized revenues) effective July 24, 2001. The PSB suspended the rate filing and a schedule was set to review the case.

     On February 9, 2001, the Vermont Supreme Court issued a decision on the Company's 1998 rate case appeal that reversed the PSB's decision on the preclusion issues and remanded the case to the PSB for further proceedings consistent with the Vermont Supreme Court's decision.

     The Company's June 26, 2001 rate order, which is described below, ended the uncertainty over the future recovery of Hydro-Quebec contract costs, and the Company will no longer incur future losses for under-recovery of Hydro-Quebec contract costs related to any allegations of imprudence prior to the June 26, 2001 rate order.

     On May 7, 2001, the Company and the DPS reached a rate case settlement that would end uncertainty over the future recovery of Hydro-Quebec contract costs, allow a 3.95 % rate increase, make the January 1, 1999 temporary rates permanent, permit a return on equity of 11% for the 12 months ending June 30, 2002 for the Vermont utility, and create new service quality standards. The Company also agreed to a 2001 second quarter $9.0 million one-time write-off ($5.3 million after-tax) of regulatory assets and a rate freeze through January 1, 2003.

     On June 26, 2001, the PSB issued an order on the Company's rate case settlement with the DPS. In addition to the provisions outlined above, the approved rate order requires the Company to return up to $16.0 million to ratepayers in the event of a merger, acquisition or asset sale if such sale requires PSB approval. As a result of the rate order, the 3.95% rate increase became effective with bills rendered July 1, 2001, and in June 2001 the Company recorded a $5.3 million after-tax loss to write off certain regulatory assets as agreed to in the settlement. The Company was able to accept the 3.95% rate increase versus the 7.6% increase it requested since 1) regulatory asset amortizations will decrease approximately $3.5 million, on a 12-month basis, due to the $9.0 million one-time write-off of regulatory assets and 2) Vermont Yankee decommissioning costs decreased approximately $1.9 million, on a 12-month basis, after the rate case was filed as a result of an agreement in p rinciple between Vermont Yankee and the secondary purchasers.

     As part of the Company's June 26, 2001 rate order, the Company agreed that all amounts collected from the Hydro-Quebec Ice Storm settlement shall be applied first to reduce the remaining balance of deferred costs related to this arbitration with the remaining balance, if any, applied to reduce other regulatory asset accounts as specified by the DPS and approved by the PSB. On July 19, 2001, Hydro-Quebec and the VJO agreed to a final settlement of the arbitration issues. Under the settlement, the VJO will continue to receive power and energy from Hydro-Quebec under this contract through 2016. As part of the settlement, Hydro-Quebec made a $9.0 million payment to the VJO in July 2001, of which the Company's share was approximately $4.3 million. In the third quarter of 2001, the Company applied approximately $2.7 million to the remaining balance of the deferred costs related to the ice storm arbitration. On October 30, 2001, the Company filed a letter with the PSB summarizi ng its agreement with the DPS on application of the remaining $1.6 million of the Hydro-Quebec settlement to remaining regulatory assets, which agreement is subject to approval by the PSB. The Company is in the process of modifying its October 30, 2001 proposal. Currently, the remaining $1.6 million balance is included as a deferred credit in the Company's Consolidated Balance Sheet.

     Connecticut Valley's retail rate tariffs, approved by the NHPUC, contain a Fuel Adjustment Clause ("FAC") and a Purchased Power Costs 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.

     In 1998, management determined that Connecticut Valley no longer qualified for the application of SFAS No. 71, and wrote off all of its regulatory assets associated with its New Hampshire retail business totaling approximately $1.3 million on a pre-tax basis. This determination was based on various legal and regulatory actions including the February 28, 1997 NHPUC Final Plan to restructure the electric utility industry in New Hampshire, a supplemental order that required Connecticut Valley to give notice to cancel its power contract with the Company and denied stranded cost recovery related to this power contract, and a December 3, 1998 Court of Appeals decision stating that Connecticut Valley's rates could be reduced to the level prevailing on December 31, 1997. The Company's petition for rehearing with the Court of Appeals as well as petition for writ of certiorari with the United States Supreme Court were subsequently denied.

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     As a result of the December 3, 1998 Court of Appeals decision, on March 22, 1999 the NHPUC issued an Order that directed Connecticut Valley to file its calculation of the difference between the total FAC and PPCA revenues that it would have collected had the 1997 FAC and PPCA rate levels been in effect the entire year. The NHPUC also directed Connecticut Valley to calculate a rate reduction to be applied to all billings for the period April 1, 1999 through December 31, 1999 to refund the 1998 over-collection relative to the 1997 rate level. The Company estimated this amount to be approximately $2.7 million on a pre-tax basis. On March 26, 1999, Connecticut Valley filed the required tariff page with the NHPUC, under protest and with reservation of all rights, and implemented the refund effective April 1, 1999.

     On April 7, 1999, the Federal District Court ("Court") ruled from the bench that the March 22, 1999 NHPUC Order requiring Connecticut Valley to provide a refund to its retail customers was illegal and beyond the NHPUC's authority. The Court also ruled that the NHPUC cannot reduce Connecticut Valley's rates below rates in effect at December 31, 1997. Accordingly, Connecticut Valley removed the rate refund from retail rates effective April 16, 1999. The Court's decision was issued as a written order on May 11, 1999.

     On May 17, 1999, the NHPUC issued an order requiring Connecticut Valley to set temporary rates at the level in effect as of December 31, 1997, subject to future reconciliation, effective with bills issued on and after June 1, 1999. On May 24, 1999, the NHPUC filed a petition for mandamus in the Court of Appeals challenging the Court's May 11, 1999 ruling and seeking a decision allowing the refunds as required by the NHPUC's March 22, 1999 Order. The Court of Appeals denied that petition on June 2, 1999. The NHPUC immediately filed a notice of appeal in the Court of Appeals, again challenging the Court's May 11, 1999 ruling. In that appeal, the Company and Connecticut Valley contended, among other things, that it is unfair for the NHPUC to direct Connecticut Valley to continue to purchase wholesale power from the Company in order to avoid the triggering of a FERC exit fee, but at the same time to freeze Connecticut Valley's rates at their December 31, 1997 level, which doe s not enable Connecticut Valley to recover all of these power costs.

     On June 14, 1999, Public Service Company of New Hampshire ("PSNH") and various parties in New Hampshire announced that a "Memorandum of Understanding" had been reached, which was intended to result in a detailed settlement proposal to the NHPUC that would resolve PSNH's claims against the NHPUC's restructuring plan. On July 6, 1999, PSNH petitioned the Court to stay its proceedings related to electric utility restructuring in New Hampshire indefinitely while the proposed settlement was reviewed and approved by the NHPUC and the New Hampshire Legislature. On July 12, 1999, the Company and Connecticut Valley objected to any stay that would allow the NHPUC's rate freeze order to remain in effect for an extended period and asked the Court to proceed with prompt hearings on its summary judgement motion and trial on the merits. On October 20, 1999, the Court heard oral arguments pertaining to the pretrial motions of the Company and the NHPUC for summary judgement and dismissal, respectively.

     On December 1, 1999, Connecticut Valley filed with the NHPUC a petition for a change in its FAC and PPCA rates effective on bills rendered on and after January 1, 2000. On December 30, 1999, the NHPUC denied Connecticut Valley's request to increase its FAC and PPCA rates above those in effect at December 31, 1997, subject to further investigation and reconciliation until otherwise ordered by the NHPUC. Accordingly, during the fourth quarter of 1999, Connecticut Valley recorded a pre-tax loss of $1.2 million for under-collection of year 2000 power costs.

     The Court of Appeals issued a decision on January 24, 2000, which upheld the Court's preliminary injunction enjoining the Commission's restructuring plan. The decision also remanded the refund issue to the Court stating:

     On March 6, 2000, the Court granted summary judgement to Connecticut Valley and the Company on their claim under the filed-rate doctrine and issued a permanent injunction mandating that the NHPUC allow Connecticut Valley to pass through to its retail customers its wholesale costs incurred under the rate schedule with the Company. The Court also ruled that Connecticut Valley was entitled to recover the wholesale costs that the NHPUC disallowed in retail rates since January 1, 1997.

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     Pursuant to the March 6, 2000 Court Order, on March 17, 2000, Connecticut Valley filed a rate request with the NHPUC for an Interim FAC/PPCA to recover the balance of wholesale costs not recovered since January 1997. To mitigate the rate increase percentage, the Interim FAC/PPCA was designed to recover current power costs and a substantial portion of past under-collections by the end of 2000; the remainder of the past under-collections were being collected during 2001 along with 2001 power costs. The NHPUC held a hearing on April 7, 2000 to review the 12.3% increase that would raise $1.6 million of revenues in 2000. The NHPUC issued an order approving the rates as temporary effective May 1, 2000.

     On July 25, 2000, the Court of Appeals affirmed the Court's March 6, 2000 Order granting summary judgement to Connecticut Valley and the Company. The NHPUC then asked the Court of Appeals to reconsider its decision. That request was denied. As a result of the favorable Court of Appeals action, Connecticut Valley recorded a $2.0 million after-tax gain in the third quarter of 2000. On November 27, 2000, the NHPUC filed a petition for writ of certiorari with the United States Supreme Court. On February 20, 2001, the Supreme Court denied the petition for writ of certiorari, thus leaving the Court of Appeals approval of the permanent injunction intact.

     In the third quarter of 2001, Management determined that Connecticut Valley is again subject to cost-based ratemaking and qualifies for the application of SFAS No. 71. This decision was based on the favorable Court of Appeals decision of July 25, 2000 and the subsequent denial of the NHPUC's petition for writ of certiorari by the United States Supreme Court on February 20, 2001 as well as other regulatory developments in New Hampshire during 2001. The application of SFAS No. 71 resulted in an extraordinary charge of $0.2 million for Connecticut Valley.

     As part of its restructuring plan, the New Hampshire Legislature enacted an Electricity Consumption Tax on customers and repealed the New Hampshire Franchise Tax on utilities, both of which became effective May 1, 2001. Since the Franchise Tax, as a credit to the New Hampshire Business Profits Tax, was larger than the Business Profits Tax, the repeal of the Franchise Tax caused Connecticut Valley to incur the Business Profits Tax. The NHPUC approved a settlement that reduced base rates to remove recovery of the Franchise Tax and implemented a Business Profits Tax Percentage Adjustment that would be subject to annual revisions in order to collect the Business Profits Tax.

     On December 31, 2001, the NHPUC ruled on Connecticut Valley's request for a Temporary Billing Surcharge to recover approximately $1.7 million of one-time costs primarily related to industry restructuring effective January 1, 2002. Connecticut Valley had proposed the Temporary Billing Surcharge to exactly offset a contemporaneously filed FAC/PPCA decrease of 9.3% such that a zero rate change would occur at January 1, 2002 and the 9.3% FAC/PPCA decrease would occur when the Temporary Billing Surcharge terminated in November 2002. The NHPUC affirmed its prior policy of considering recovery of costs related to industry restructuring at the time retail choice is implemented in the Connecticut Valley service area. Thus the NHPUC deferred action on all but $125,000, for which recovery was allowed through November 30, 2002.

     On December 31, 2001 the NHPUC approved Connecticut Valley's FAC and PPCA rates for 2002 as well as Connecticut Valley's Business Profits Tax Adjustment Percentage and Conservation and Load Management Percentage Adjustment for 2002. Combined with the Temporary Billing Surcharge, the result was an overall 8.6% rate reduction with a revenue decrease of $1.8 million.

     The New Hampshire electric utilities began delivery of consistent, statewide energy efficiency programs on
June 1, 2002. The NHPUC had previously approved the design of common, core efficiency programs and on February 27, 2002, Connecticut Valley proposed implementation of specific, non-core energy efficiency programs with recovery of costs for all the energy efficiency programs via an Interim 2002 - 2003 Conservation and Load Management Percentage Adjustment effective June 1, 2002 in accordance with NHPUC Order No. 23,850. Connecticut Valley had ceased providing such programs in 1997. On May 31, 2002, the NHPUC approved Connecticut Valley's proposal including a 1.4% increase in average retail rates to recover the costs. As required by the NHPUC order, the efficiency programs and related rate increase became effective June 1, 2002.

     On May 30, 2002, the NHPUC issued an Order approving statewide low-income energy assistance programs referred to as the Tiered Discount Program ("TDP"). Under this program, New Hampshire electric utilities would collect a system benefits charge, apply discounted rates to participant bills, forgive any past due balances until August 31, 2002, deduct any authorized start-up and administrative costs, and remit the balance to the State. The statewide system benefits charge fund would make up the shortfall if the system benefits charge does not wholly reimburse a particular utility. In the Order, the NHPUC also approved a $0.0012 per Kwh surcharge for Connecticut

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Valley (which is not subject to the system benefits charge) to fund the TDP. On July 31, 2002, as required in the Order, Connecticut Valley filed its compliance tariffs with the NHPUC. Connecticut Valley and several other New Hampshire utilities are required to implement the TDP no later than October 1, 2002.

     On February 28, 1997, Connecticut Valley was directed by the NHPUC to terminate its purchase of power from the Company. The Company filed an application with the FERC in June 1997, to recover stranded costs in connection with its wholesale rate schedule with Connecticut Valley and the notice of cancellation of that rate schedule (contingent upon the recovery of the stranded costs that would result from the cancellation of that rate schedule). In December 1997, the FERC rejected the Company's proposal to recover stranded costs through the imposition of a surcharge in the Company's transmission tariff, but indicated that it would consider an exit fee mechanism in the wholesale rate schedule for collecting stranded costs. The FERC denied the Company's motion for a rehearing regarding the transmission surcharge proposal. However, the Company filed a request with the FERC for an exit fee mechanism in the wholesale rate schedule to collect the stranded costs resulting from the

cancellation of the wholesale rate schedule. The stranded cost obligation sought to be recovered was $90.6 million in nominal dollars and $44.9 million on a net present value basis as of December 31, 1997.

     On April 24, 2001, a FERC Administrative Law Judge ("ALJ") issued an Initial Decision in the Company's stranded cost/exit fee proceeding. The ALJ ruled that if Connecticut Valley terminates its relationship as a wholesale customer of the Company and subsequently becomes a wholesale transmission customer of the Company, Connecticut Valley shall be liable for payment of stranded costs to the Company. The ALJ calculated, on an illustrative pro-forma basis, a nominal stranded cost obligation of nearly $83.0 million through 2016. The amount of the exit fee as determined by the ALJ will decrease with each year that service continues and normal tariff revenues are collected, and will ultimately be calculated from the date of termination, if notice of termination is ever given. Absent termination of the wholesale rate schedule by mutual agreement, the earliest termination date that could presently occur pursuant to the wholesale rate schedule is December 31, 2003. The stranded c ost obligation as of December 31, 2003, expressed on a net present value basis set forth in the ALJ order, is approximately $33.9 million.

     The ALJ's Initial Decision is subject to review and approval by the FERC. If the Company is unable to obtain approval by the FERC, and if Connecticut Valley is forced to terminate its relationship as a wholesale customer of the Company, it is possible that the Company would be required to recognize a pre-tax loss under this contract totaling approximately $32.9 million as of December 31, 2003. The Company would also be required to write-off approximately $0.8 million (pre-tax) of regulatory assets associated with its wholesale business as of December 31, 2003. If the Company obtains a FERC order authorizing the updated requested exit fee and notice of termination is given, Connecticut Valley will apply to the NHPUC to increase rates in order to pay the exit fee. The Company believes that the NHPUC must permit Connecticut Valley to raise rates to recover the cost of the exit fee. However, if Connecticut Valley is unable to recover its costs in rates, Connecticut Valley a nd, therefore the Company would be required to recognize the loss discussed above.

     In addition to its efforts before the Court and FERC, Connecticut Valley has initiated efforts and will continue to work for a negotiated settlement with parties to the New Hampshire restructuring proceeding and the NHPUC.

     An adverse resolution of the FERC and New Hampshire proceedings would have a material adverse effect on the Company's results of operations, financial condition and cash flows. However, the Company cannot predict the ultimate outcome of this matter.

     Connecticut Valley purchases power from several Independent Power Producers, who own qualifying facilities as defined by the Public Utility Regulatory Policies Act of 1978. For the six months ended June 30, 2002, under long-term contracts with these qualifying facilities, Connecticut Valley purchased 19,915 mWh, of which 92% was purchased from Wheelabrator Claremont Company, L.P., ("Wheelabrator") who owns a waste-to-energy electric generating facility. Connecticut Valley had filed a complaint with the FERC stating its concern that Wheelabrator has not been a qualifying facility since the facility began operation. On February 11, 1998, the FERC issued an Order denying Connecticut Valley's request for a refund of past purchased power costs and lower future costs. Connecticut Valley filed a request for rehearing with the FERC on March 13, 1998, which was denied. Connecticut Valley appealed to the D.C. Circuit Court of Appeals, which denied the appeal, but indicated tha t Connecticut Valley could seek relief from the NHPUC. On May 12, 2000, Connecticut Valley filed a petition with the NHPUC seeking 1) to amend the contract to permit purchase of net, rather than gross, output of the facility and 2) a refund, with interest, of past purchases of the difference between net and gross output.

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     In December 2000 and January 2001, Wheelabrator, the New Hampshire/Vermont Solid Waste District, and several Connecticut Valley residential customers filed with the NHPUC to intervene. The Office of Consumer Advocate and the NHPUC Staff are automatic parties. A Prehearing Conference was held before the NHPUC on January 4, 2001, at which time each party provided preliminary position statements with regard to the petition. In February and March 2001, the parties filed briefs on the legal issues and Wheelabrator filed a motion to dismiss.

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

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

     A hearing on the Stipulation of Settlement was held on June 7, 2002. The focus of the hearing was to determine whether the Stipulation is in the public interest. In that hearing the NHPUC requested that Connecticut Valley provide additional information regarding the settlement and Connecticut Valley provided the information on June 20, 2002. The NHPUC issued an Order on July 5, 2002, in which it did not rule on the Stipulation of Settlement and instead announced that it will appoint an independent mediator who would work with all parties to see if a mutually agreeable settlement of the case could be achieved. On July 11, 2002, the NHPUC issued a Request for Proposal for a consultant to provide mediation services in this matter. The Company cannot predict the timing or final outcome of this matter.

     The Company is engaged in various operations and activities that subject it to inspection and supervision by both federal and state regulatory authorities including the United States Environmental Protection Agency ("EPA"). It is Company policy to comply with all environmental laws. The Company has implemented various procedures and internal controls to assess and assure compliance. If non-compliance is discovered, corrective action is taken. Based on these efforts and the oversight of those regulatory agencies having jurisdiction, the Company believes it is in compliance, in all material respects, with all pertinent environmental laws and regulations.

     Company operations occasionally result in unavoidable, inadvertent releases of regulated substances or materials; for example, the rupture of a pole-mounted transformer or a broken hydraulic line. Whenever the Company learns of such a release, the Company responds in a timely fashion and in a manner that complies with all federal and state requirements. Except as discussed in the following paragraphs, the Company is not aware of any instances where it has caused, permitted or suffered a release or spill on or about its properties or otherwise which is likely to result in any material environmental liabilities to the Company.

     The Company is an amalgamation of more than 100 predecessor companies. Those companies engaged in various operations and activities prior to being merged into the Company. At least two of these companies were involved in the production of gas from coal to sell and distribute to retail customers at four different locations. The Company discontinued these activities in the late 1940s or early 1950s. The coal gas manufacturers, other predecessor companies and the Company itself may have engaged in waste disposal activities which, while legal and consistent with commercially accepted practices at the time, may not meet modern standards and thus represent potential liability.

     The Company continues to investigate, evaluate, monitor and, where appropriate, remediate contaminated sites related to these past activities. The Company's policy is to accrue a liability for those sites where costs for remediation, monitoring and other future activities are probable and can be reasonably estimated. As part of that process, the Company also researches the possibility of insurance coverage that could defray any such remediation expenses.

Cleveland Avenue Property The Company's Cleveland Avenue property, located in the City of Rutland, Vermont, was a site where one of its predecessors operated a coal-gasification facility and later the Company sited various operations functions. Due to the presence of coal tar deposits and Polychlorinated Biphenyl ("PCB") contamination

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and uncertainties as to potential off-site migration of those contaminants, the Company conducted studies in the late 1980s and early 1990s to determine the magnitude and extent of the contamination. After completing its preliminary investigation, the Company engaged a consultant to assist in evaluating clean-up methodologies and provide cost estimates. Site investigation has continued over the last several years and the Company continues to work with the State of Vermont in a joint effort to develop a mutually acceptable solution.

Brattleboro Manufactured Gas Facility From the early to late 1940s, the Company owned and operated a manufactured gas facility in Brattleboro, Vermont. The Company commissioned an environmental site assessment in late 1999 upon request by the State of New Hampshire. In early 2001, the Company submitted a work plan to the State of New Hampshire to address their concerns and in October 2001 the Company received a Certificate of No Further Action from the State of New Hampshire; however, the State reserves the right to require additional investigation or remedial measures, if necessary. In the third quarter of 2001, the Company submitted a corrective action plan to the State of Vermont. On January 17, 2002, the Company received a letter from the Vermont Agency of Natural Resources notifying the Company that its corrective action plan for the site is approved. The Company implemented the corrective action plan, which is now in place, including periodic groundwater monitoring and institutio nal controls.

Dover, New Hampshire, Manufactured Gas Facility In late 1999, the Company was contacted by PSNH with respect to this site. PSNH alleged the Company was partially liable for remediation of the site. PSNH's allegation was premised on the fact that prior to PSNH's purchase of the facility, it was operated by Twin State Gas and Electric ("Twin State"). Twin State merged with the Company on the same day the facility was sold to PSNH. The Company and PSNH agreed to and have participated in non-binding mediation regarding liability.

     In December 2000, PSNH submitted a work plan to the State of New Hampshire for further investigation of this site. The Company agreed, with reservations, to participate on a limited basis in the development and completion of the work plan since the State of New Hampshire considers the Company, along with others, as potentially responsible parties at the site. The Company, PSNH and Keyspan Energy hired a contractor, which completed the fieldwork in October 2001. A report will be published and submitted to the State of New Hampshire in August 2002.

     Having previously agreed to non-binding mediation, a mediator on the issue of liability was chosen in April 2001 and the first phase of mediation, or "Phase I", was concluded on July 18, 2001. Without admitting liability, both the Company and PSNH agreed to participate in the site remediation for those years that Twin State and PSNH were responsible. On October 30 and 31, 2001, the Company and PSNH met with the other potentially responsible parties in a "Phase II" mediation process. The subject of the Phase II mediation was the liability of other potentially responsible parties at the site, in particular those that owned the property after Twin State and PSNH. The Phase II mediation process in 2001 did not achieve the goal of a general agreement on liability between the participants. In the first quarter of 2002, Phase II negotiations continued but did not achieve the goal of a general agreement on liability between the participants.

     In the second quarter of 2002, the Company reached a settlement agreement with PSNH regarding the Dover site in which neither party admitted liability or the allegations made against them by the New Hampshire Department of Environmental Services. Under the settlement agreement, the Company agreed to transfer and assign to PSNH certain liabilities it may have related to the site, in exchange for an agreed upon amount to be paid by the Company to PSNH for its ongoing share of Qualified Site Liability Costs.

     Based on the terms of the Dover settlement agreement reached with PSNH, in the second quarter of 2002, the Company reversed $1.7 million of its environmental reserves, resulting in a $1.0 million after-tax favorable earnings impact. As of June 30, 2002, a reserve of $7.5 million is recorded on the Consolidated Balance Sheet representing management's best estimate of the costs to remediate the sites discussed above.

     The Company is not subject to any pending or threatened litigation with respect to any other sites that have the potential for causing the Company to incur material remediation expenses, nor has the EPA or any other federal or state agency sought contribution from the Company for the study or remediation of any such sites.

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     The 8.3% Dividend Series Preferred Stock is redeemable at par through a mandatory sinking fund in the amount of $1.0 million per annum and, at its option, the Company may redeem at par an additional non-cumulative $1.0 million per annum. The Company paid the mandatory sinking fund payment in the amount of $1.0 million in the first quarter of 2002.

     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 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; Connecticut Valley Electric Company Inc. ("CVEC"), which distributes and sells electricity in parts of New Hampshire; Catamount Energy Corporation ("Catamount"), which has investments in non-regulated, energy generation projects in the United States and Western Europe; and Eversant Corporation ("Eversant"), which pursued retail alliances to market energy and related products and services, and also engages in the sale of or rental of electric water heaters through a subsidiary to customers in Vermont and New Hampshire. As of June 30, 2002, Eversant had a 12.1% ownership interest, on a fully diluted basis, in the Home Services Store ("HSS"), which operates a nationwide home improvement business.  The Company has decided to discontinue Eversant's efforts to pursu e non-regulated business opportunities. CVEC, while managed on an integrated basis with CV, is presented separately because of its separate and distinct regulatory jurisdiction. Other operating segments include a segment below the quantitative threshold for separate disclosure. This operating segment is 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. Segment information for 2001 has been expanded to include equity income.

     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 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 three and six months ended June 30, 2002 and 2001 is as follows (dollars in thousands):

(1)     Includes a segment below the quantitative threshold.

(2)     Includes a segment below the quantitative threshold.

Derivative Instruments: On January 1, 2001, the Company adopted SFAS No. 133 (subsequently amended by SFAS No. 137 and 138), Accounting for Derivative Instruments and Hedging Activities ("SFAS No. 133"). This Statement, as amended, establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met.

     The Company has one long-term purchase power contract that allows the seller to purchase specified amounts of power with advance notice (Hydro-Quebec Sellback #3). This contract has been determined to be a derivative under SFAS No. 133. On April 11, 2001, the PSB approved an Accounting Order that requires the fair valuation adjustment of this contract to be deferred on the balance sheet as either a deferred asset or liability. At June 30, 2002, this derivative had an estimated fair market value of approximately a $1.0 million unrealized loss, which is included in Other deferred credits on the Consolidated Balance Sheet along with an offsetting deferred asset, which is included in Other deferred charges.

Goodwill and Other Intangible Assets: In July 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets ("SFAS No. 142"), effective for fiscal years beginning after December 15, 2001. SFAS No. 142 establishes a new accounting standard for the treatment of goodwill. The new standard continues to require

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recognition of goodwill as an asset in a business combination but does not permit amortization as is done under current accounting standards. Effective January 1, 2002, SFAS No. 142 requires that goodwill be separately tested for impairment using a fair-value based approach as opposed to the undiscounted cash flow approach used under current accounting standards. If goodwill is found to be impaired, the Company would be required to record a non-cash charge against income, which would be recorded as a cumulative effect of a change in accounting principle. The impairment charge would be equal to the amount by which the carrying amount of the goodwill exceeds its estimated fair value. There was no material financial statement impact resulting from the Company's implementation of SFAS No. 142.

Asset Retirement Obligations: In August 2001, the 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 in the period in which it is incurred. The Company has identified potential retirement obligations associated with the decommissioning of its nuclear facilities, but has not yet completed its assessment. This statement is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Company has not yet quantified the impacts, if any, of adopting SFAS No. 143 on its financial statements.

Impairment or Disposal of Long-Lived Assets: In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS No. 144") which replaces SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. This statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. Although SFAS No. 144 supercedes SFAS No. 121, it retains the fundamental provisions of SFAS No. 121 regarding

recognition/measurement of impairment of long-lived assets to be held and used and measurement of long-lived assets to be disposed of by sale. Under SFAS No. 144, asset write-downs from discontinuing a business segment will be treated the same as other assets held for sale. The new standard also broadens the financial statement presentation of discontinued operations to include the disposal of an asset group (rather than a segment of a business). SFAS No. 144 is effective beginning January 1, 2002 and, generally, is to be applied prospectively. The Company adopted SFAS No. 144 in the first quarter of 2002, and there was no material impact on its financial statements.

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     This discussion should be read in conjunction with the consolidated financial statements and footnotes in this Form 10-Q, the 2001 Form 10-k and current reports on Form 8-K dated March 4, 2002, March 22, 2002,
July 22, 2002, July 24, 2002 and July 31, 2002.

Forward-Looking Statements Statements contained in this report that are not historical fact (including Management's Discussion and Analysis of Financial Condition and Results of Operations) are forward-looking statements intended to qualify for the safe-harbors from liability established by the Private Securities Reform Act of 1995. Statements made that are not historical facts are forward-looking and, accordingly, involve estimates, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Actual results will depend, among other things, upon the actions of regulators, the outcome of litigation at the Federal Energy Regulatory Commission ("FERC") involving the Company's regulated companies, the outcome of litigation at the Vermont Public Service Board ("PSB"), the performance of the Vermont Yankee nuclear power plant ("Vermont Yankee"), weather conditions, the performance of the Company's non-regul ated businesses and the state of the economy in the areas served. The Company cannot predict the outcome of any of these matters.

     Preparation of the Company's financial statements in accordance with accounting principles generally accepted in the United States requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities and revenues and expenses. Note 1 in the Company's 2001 Form 10-K to the Consolidated Financial Statements is a summary of the significant accounting policies used in the preparation of the Company's financial statements. The following is a discussion of the most critical accounting policies used by the Company.

Regulation The Company is subject to regulation by the PSB, the New Hampshire Public Utilities Commission ("NHPUC") and the 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 No. 71, "Accounting for the Effects of Certain Types of Regulation", or SFAS No. 71, for both its regulated service territories and FERC-regulated wholesale businesses. In order for a company to report under SFAS No. 71, the Company's rates must be designed to recover its costs of providing service and must be able to collect those rates from customers. If rate recovery becomes unlikely or uncertain, whether due to competition or regulatory action, this accounting standard would no longer apply to the Company's regulated operations. In the event the Company determines that it no longer meets the criteria for applying SFAS No. 71, in one or more of its jurisdictions, the accounting impact would be an extraordinary non-cash charge to operations of approximately $29.0 million on a pre-tax basis as of June 30, 2002. See Note 2, Regulatory Accounting, for more detail. Criteria that give rise to the discontinuance of SFAS No. 71 include 1) increasing competition that restricts the Company's ability to establish prices to recover specific costs and 2) a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. Management periodically reviews these criteria to ensure the continuing application of SFAS No. 71 is appropriate. Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, Management believes future recovery of its regulatory assets in the State of Vermont and the State of New Hampshire for the Company's retail and wholesale businesses are probable.

Valuation of Long-Lived Assets The Company periodically evaluates the carrying value of long-lived assets and long-lived assets to be disposed of, including its investments in nuclear generating companies, its unregulated investments, and its interests in jointly owned generating facilities, when events and circumstances warrant such a review. The carrying value of such assets is considered impaired when the anticipated undiscounted cash flow from such an asset is less than its carrying value. In that event, a loss is recognized based on the amount by which the carrying value exceeds the fair value of the long-lived asset. Based on Management's review, certain of Catamount's investments were impaired at December 31, 2001. See Diversification below for further discussion.

Purchased Power The Company records the annual cost of power obtained under long-term contracts as operating expenses. Since these contracts do not convey to the Company the right to use property, plant or equipment, they are considered executory in nature.

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Other Other significant accounting policies include: 1) estimated unbilled revenues recorded at the end of each quarterly accounting period; 2) depreciation based on the straight-line remaining life method; and 3) income taxes recorded in accordance with SFAS No. 109, "Accounting for Income Taxes."

     The Company recorded net income of $4.0 million, or $.31 per basic and $.30 per diluted share of common stock, for the second quarter of 2002 compared to net income of $0.3 million, or a loss of $.01 per basic and diluted share of common stock, for the second quarter of 2001. Higher second quarter 2002 earnings compared to the same period in 2001 resulted from the following factors:

• higher retail sales revenue and other operating revenue of $1.5 million after-tax, or $.13 per share of common stock, primarily resulting from higher average retail rates due to the June 26, 2001 rate order, which allowed for a 3.95% increase in retail rates beginning July 1, 2001;

• higher net power costs of $1.7 million after-tax, or $.14 per share of common stock, primarily related to a 2001 reversal of a December 2000 accrual for estimated costs for installed capacity deficiency charges in ISO-New England with no similar reversal in 2002;

• higher operating and other costs of $0.3 million after-tax, or $.03 per share of common stock, primarily related to a $0.2 million, or $.02 per share of common stock, increase in bad debt reserves due to several announced bankruptcies, higher transmission costs of $0.3 million, or $.03 per share of common stock, lower interest and dividend income of $0.2 million, or $.02 per share of common stock, higher property taxes of $0.2 million, or $.02 per share of common stock, and higher life insurance expense due to market fluctuations of $0.4 million, or $.03 per share of common stock, partially offset by a $1.0 million, or $.09 per share of common stock, reversal of certain environmental reserves;

• higher earnings at Catamount Energy Corporation of $0.3 million, or $.03 per share of common stock, primarily related to lower equity losses on its current equity investments;

• higher earnings at Eversant Corporation of $0.3 million, or $.02 per share of common stock, due to the settlement of an IRS audit resulting in a reversal of an IRS interest expense accrual previously recorded in the fourth quarter of 2001 and lower business development costs, partially offset by severance costs related to the Company's decision to discontinue Eversant's efforts to pursue non-regulated business opportunities; and

• the Company's June 26, 2001 rate order, which resulted in a net after-tax charge of $3.6 million, or $.31 per share of common stock, due to a one-time write-off of $5.3 million after-tax, or $.46 per share of common stock, of certain regulatory assets, partially offset by the elimination of charges for the under recovery of costs related to the Hydro-Quebec power contract, which resulted in a favorable $1.7 million after-tax impact, or $.15 per share of common stock, with no similar items in 2002.

     For the six months ended June 30, 2002 the Company had net income of $8.8 million, or $.68 per basic and $.67 per diluted share of common stock, compared to net income of $4.2 million, or $.29 per basic and diluted share of common stock, for the first six months of 2001. Higher first six months 2002 earnings compared to the same period last year resulted primarily from the following factors:

• higher retail sales revenue and other operating revenue of $2.0 million after-tax, or $.17 per share of common stock, primarily resulting from higher average retail rates due to the June 26, 2001 rate order, which allowed for a 3.95% increase in retail rates beginning July 1, 2001, offset by a .77% (8,896 mWh) decrease in retail mWh sales mostly due to milder winter weather in 2002;

• higher net power costs of $1.8 million after-tax, or $.15 per share of common stock, primarily related to a 2001 reversal of a December 2000 accrual for estimated costs for installed capacity deficiency charges in ISO-New England with no similar reversal in 2002 and higher output from more costly Independent Power Producers, offset by lower purchased installed capacity costs;

• lower operating and other costs of $0.6 million after-tax, or $.05 per share of common stock, primarily related to the following after-tax items: a $1.0 million, or $.09 per share of common stock, reversal of certain environmental reserves, lower storm restoration costs of $0.6 million, or $.05 per share of common stock, higher transmission costs of $0.7 million, or $.06 per share of common stock, and a $0.4 million, or $.04 per share of common stock, increase in bad debt reserves due to several announced bankruptcies;

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• higher earnings at Catamount Energy Corporation of $0.4 million, or $.03 per share of common stock, primarily related to lower equity losses on its current equity investments, higher equity earnings on Appomattox, offset by higher project development costs;

• higher losses at Eversant Corporation of $0.2 million, or $.01 per share of common stock, primarily related to the Company's decision to discontinue Eversant's efforts to pursue non-regulated business opportunities, partially offset by the settlement of an IRS audit resulting in a reversal of an IRS interest expense accrual previously recorded in the fourth quarter of 2001; and

• the Company's June 26, 2001 rate order, which resulted in a net after-tax charge of $3.6 million, or $.31 per share of common stock, due to a one-time write-off of $5.3 million after-tax, or $.46 per share of common stock, of certain regulatory assets, partially offset by the elimination of charges for the under recovery of costs related to the Hydro-Quebec power contract, which resulted in a favorable $1.7 million after-tax impact, or $.15 per share of common stock, with no similar items in 2002.

     Other factors affecting results for the first quarter of 2002 are described in the following Results of Operations.

Operating revenues and megawatt-hour ("mWh") sales A summary for 2002 and 2001 follows:

     Retail sales revenue increased $2.1 million, or 3.3%, for the second quarter of 2002 and $3.1 million, or 2.3%, for the first half of 2002 compared to the second quarter of 2001 and the first half of 2001, respectively. The increase in retail sales revenue resulted from the 3.95% retail rate increase, which became effective July 1, 2001.

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Both the second quarter of 2002 and the first half of 2002 had slight decreases in retail mWh sales, .2% and .8% respectively, compared to the same periods in 2001, which partially offset the favorable impact of the 3.95% retail rate increase. The decrease in mWh sales is primarily related to milder winter weather compared to 2001.

     Entitlement sales in the second quarter of 2001 and the first half of 2001 were related to a five-year power contract in which the Company sold approximately 15% of its share of Vermont Yankee output at full cost; that contract ended in October 2001. The additional output that the Company receives from Vermont Yankee due to the discontinuance of this contract is either used to support its own-load needs or sold in the short-term market mostly to ISO-New England.

     Other resale sales revenue and mWh sales in the second quarter of 2002 decreased by 27.1% and 13.2%, respectively, compared to the second quarter of 2001, primarily due to the Vermont Yankee mid-cycle outage in May 2002, which resulted in fewer short-term market sales, primarily in ISO-New England compared to the same period in 2001. In addition, average ISO-New England market prices in 2002 have been much lower than in 2001.

     For the first half of 2002, Other resale sales revenue decreased $2.2 million, or 21.4%, compared to the first half of 2001, primarily due to the lower market rates in ISO-New England. Related mWh sales for the same period increased 8% primarily due to the end of the Vermont Yankee entitlement sale and a 11.8% increase in the Company's share of Vermont Yankee output beginning March 1, 2002, as a result of the early return of Vermont Yankee entitlements from the secondary purchasers as described in Nuclear Matters, Vermont Yankee - Sale below. The increase in mWh sales was limited to 8% due to the Vermont Yankee mid-cycle outage in May 2002.

     Other revenues in the second quarter of 2002 and the first half of 2002 are $0.4 million and $0.3 million higher than the comparable periods in 2001 primarily due to the sale of non-firm transmission under Tariff 7, which began in late 2001.

Net Purchased Power and Production Fuel The cost components of net purchased power and production fuel for the three and six months ended June 30, 2002 and 2001 are as follows (dollars in thousands):

     Capacity costs increased $5.1 million in the second quarter of 2002 compared to the same period in 2001 primarily due to nonrecurring items in the second quarter of 2001 including 1) the June 26, 2001 rate order which ended the Hydro-Quebec power cost disallowances resulting in a $2.9 million reversal of a second quarter 2001 accrual for under recovery of power costs, and 2) a $2.5 million reversal of a December 2000 accrual for estimated

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costs for installed capacity ("ICAP") in ISO-New England due to the resolution of a December 2000 FERC Order. Excluding these nonrecurring items, capacity costs decreased approximately $0.3 million due to lower purchased ICAP costs and lower Vermont Yankee capacity costs, partially offset by the Company's increased entitlement in Vermont Yankee due to the end of the Vermont Yankee entitlement sale and the early return of Vermont Yankee entitlements from the secondary purchasers as described above.

     For the first half of 2002, capacity costs increased $4.6 million compared to the same period in 2001 primarily due to the second quarter 2001 nonrecurring items explained above. Excluding the nonrecurring items, capacity costs decreased $0.9 million for the first half of 2002 compared to the same period in 2001 due primarily to lower Vermont Yankee capacity costs and lower purchased ICAP costs, offset by the increased entitlement in Vermont Yankee and higher output from Independent Power Producers compared to 2001.

     In May 2002, Vermont Yankee had an unscheduled refueling outage, starting May 11 and ending May 23, in order to replace defective fuel rods. The Company requested and received PSB approval of an Accounting Order to defer the incremental costs for inclusion in rates at the next retail rate case. In June 2002, the Company deferred approximately $3.8 million of the costs related to the unscheduled outage and those costs are included in Other deferred charges in the Consolidated Balance Sheet. For additional information regarding the Accounting Order see Nuclear Matters, Vermont Yankee - Operations below.

     Energy purchases decreased $3.8 million for the second quarter of 2002 and $5.1 million for the first half of 2002 compared to the same periods in 2001 due to certain purchases made in 2001 but not in 2002, including Hydro-Quebec 9600, a contract in which the Company purchased power from Hydro-Quebec and resold the power in ISO-New England, and the Hydro-Quebec Firm Energy Contract, which expired in 2001. Offsetting these were increased costs from the independent power producers due to higher volume. Additionally, Vermont Yankee purchases increased due to the Company's increased entitlement in Vermont Yankee as explained above and higher Vermont Yankee output resulting from a full refueling outage in the second quarter of 2001 compared to the shorter mid-cycle outage in May 2002.

     Production fuel costs decreased $0.1 million and $0.5 million for the second quarter of 2002 and first half of 2002, respectively, compared to the same periods in 2001 primarily due to lower output at the Wyman and McNeil generating stations in 2002. During 2001, McNeil had increased operations to support reliability and Wyman continues to reduce operations due to unfavorable economics.

     The Company maintains a 1.7303% joint-ownership interest in Unit #3 of the Millstone Nuclear Power Station and owns a 2%, 2% and 3.5% equity interest in Connecticut Yankee, Maine Yankee and Yankee Atomic, respectively. In the first quarter of 2002, the Company's ownership percentage of Vermont Yankee changed from 31.3% to 33.23% related to the repurchase of shares held by minority owners of the plant. On July 31, 2002, the Vermont Yankee plant was sold to Entergy, however the Company continues to have a 33.23% equity interest in the successor corporation, which will administer the long term power purchase contract between Entergy and former utility owners of the Vermont Yankee plant. The Company's entitlement percentage of Vermont Yankee's output continues to be 35%. See Vermont Yankee - Sale below for more detail.

     On March 31, 2001, the sale of Northeast Utilities' ownership of Millstone Unit #3 to Dominion Nuclear Connecticut ("DNC"), a subsidiary of Dominion Resources, Inc., became final. Millstone Unit #3 continues to be a jointly owned plant, and the Company is one of two minority owners, however the total DNC share is 93.4707%.

     As part of the regulatory approvals of the sales to DNC by the joint owners of that plant, DNC has represented to the Nuclear Regulatory Commission ("NRC") and other regulatory bodies, including the Connecticut Department of Public Utility Control, that the Millstone Unit #3 Decommissioning Trust Fund, for its share of the plant, exceeds the NRC minimum calculation required and therefore no further contributions to the fund are required at this time. The Company has agreed with the DPS position in its recent rate case that the DNC representation that contributions currently can cease is appropriate subject to periodic review of both the fund balance and the NRC minimum calculation upon which the DNC bases its assertion of fund adequacy. The Company could choose to renew funding at its own discretion as long as the minimum requirement is met or exceeded.

     On August 15, 2001, Vermont Yankee announced that a sales agreement had been reached with Entergy Corporation ("Entergy") for $180 million, representing $145 million for the plant and related assets and $35 million for nuclear fuel. Entergy will also assume decommissioning liability for the plant and its decommissioning trust

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fund. The agreement includes a purchase power contract with prices that generally range from 3.9 cents to 4.5 cents per kilowatt-hour subject to a "low-market adjuster" that protects the current Vermont Yankee owner-utilities, including the Company and its power consumers, in the event power market prices drop significantly. On September 27, 2001, the Company filed testimony with the Vermont Public Service Board ("PSB") in support of the sale. In an order entered October 26, 2001, the PSB granted intervention to several parties that the Company did not oppose, and established a schedule that provided for discovery, hearings and final briefing by April 29, 2002. Certain of the intervenors were secondary purchasers of Vermont Yankee power, which were seeking adjustments in their power purchase contracts, and stockholders of Vermont Yankee, which were asserting dissenters' rights. On January 16, 2002, Vermont Yankee announced that it had reached an agreement with the secondary purchasers and had repurch ased the shares held by the minority stockholders; these parties requested to withdraw from the PSB proceeding. On January 16, 2002, as a result of the repurchased shares, the Company's ownership percentage of Vermont Yankee changed from 31.3% to 33.23%.

     Following hearings on February 4 - 8 and 14 - 15, 2002, the Company, Green Mountain Power ("GMP"), Vermont Yankee and Entergy filed rebuttal testimony. On March 6, 2002, the Company, GMP, Vermont Yankee, Entergy and the Department of Public Service ("DPS") filed a joint Memorandum of Understanding ("MOU") that resolved all issues raised by the DPS earlier in the proceeding and in which the MOU parties recommend approval of the sale in accordance with the terms of the MOU. The intervenors did not join in the MOU. During April 2002, the Board held hearings on the rebuttal testimony of all parties as well as the MOU. All parties filed Initial Briefs on May 7, 2002, with Reply Briefs filed on May 14, 2002.

     On May 17, 2002, the Nuclear Regulatory Commission approved the transfer of the Vermont Yankee operating license to Entergy. The FERC approved the sale on February 1, 2002.

     On June 13, 2002, the PSB issued an Order approving the Vermont Yankee sale to Entergy, along with the associated power purchase agreement between the current owners and Entergy. In approving the transactions, the PSB largely accepted the terms of the MOU reached between the current owners, Entergy and the DPS, however the PSB set several conditions, including:

• Requiring that any money remaining in the decommissioning fund following completion of decommissioning be returned to consumers;
• Requiring that the Company and GMP submit plans for using their share of any excess remaining in the decommissioning fund, toward the development and use of renewable resources for Vermont;
• Significant financial guarantees and corporate commitments from Entergy's parent corporation, ensuring the reliability of its subsidiaries' commitments;
• Requiring the Company to file an updated cost-of-service and appropriate additional information as necessary in April 2003 to determine whether a rate decrease is appropriate in 2003 or 2004; and
• Prohibiting Entergy from operating Vermont Yankee after March 31, 2012 without prior approval of the PSB.

     On June 21, 2002, Entergy filed a Motion to Alter or Amend the PSB's June 13 Order to accept the agreement between the Vermont Yankee owners and the DPS as written and allow the 50-50 sharing with ratepayers of any excess remaining in Vermont Yankee's decommissioning trust fund after the decommissioning is completed after 2022. On July 1, 2002, the DPS issued a response to the PSB regarding Entergy's Motion requesting that the PSB reconsider its ruling of June 13, 2002 and recommended that any excess decommissioning funds be split between ratepayers and Entergy. On July 11, 2002, the PSB rendered a decision on Entergy's Motion in which the PSB confirmed its June 13, 2002 Order.

     On July 18, 2002, Entergy announced that it would not accept the condition included by the PSB in its June 13, 2002 Order and its July 11, 2002 ruling confirming that Order. Instead Entergy said it would examine ways to reengineer the terms of the sale to produce a mutually acceptable agreement within the 12 days left to close the sale.

     On July 22, 2002, Entergy and the utility owners of Vermont Yankee reached agreements that would allow the sale to close before July 31, 2002 when the purchase agreement ends. Under the terms of the agreements, Vermont ratepayers will receive 100% of the Vermont utilities' share of any surplus remaining in the decommissioning fund when the plant is decommissioned. The non-Vermont owners, representing 45% ownership of the plant, will restore the substance of the original agreement by assigning 100% of their excess decommissioning funds to Entergy. The Company and GMP agreed to contribute $1.5 million in stockholder funds to the non-Vermont utility owners of the plant to provide parity for assigning their share of the decommissioning fund to Entergy. The Company's share is approximately $950,000 pre-tax and would be expensed upon the closing of the sale.

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     On July 23, 2002, the New England Coalition on Nuclear Pollution ("NECNP") and the Citizens Awareness Network ("CAN") filed a Petition for Temporary Restraining Order and Preliminary Injunction regarding the July 22, 2002 proposed sale terms between Entergy, the Vermont Yankee owners, GMP and the Company. On July 26, 2002, the PSB denied the request for Temporary Restraining Order and found that the July 22, 2002 agreements between Entergy and the utility owners of Vermont Yankee met all of the conditions the PSB placed on its earlier approval of the sale.

     On July 29, 2002, NECNP and CAN filed a Complaint with the FERC, seeking a "fast track" hearing to delay the sale. The FERC has provided notice of the complaint, requesting that answers, comments, interventions or protests must be filed by August 19, 2002.

     On July 29, 2002, NECNP and CAN filed with the PSB Motions to Alter or Amend, Enter Final Judgement, and Stay pending Appeal. Additional petitions were filed by intervenors and others with the regulatory commissions of New Hampshire, Massachusetts and Maine. On July 30, 2002, the PSB and the Maine and Massachusetts commissions issued rulings approving the sale and denying the requests for stays. On July 31, 2002, the New Hampshire commission issued its ruling approving the sale.

     The Securities and Exchange Commission approved the sale on July 30, 2002.

     On July 31, 2002, Vermont Yankee completed the sale of its assets to Entergy. The Company continues to have a 33.23% equity interest in Vermont Yankee Nuclear Power Corporation that will continue as a Vermont-based entity that will administer the purchase power contracts among the former utility owners and Entergy. The Company will continue to receive its 35% entitlement of Vermont Yankee output under the purchase power agreement described above. Additionally, two remaining secondary purchasers will continue receiving a small percentage of the Company's entitlement.

     The sale is expected to save the Company's customers at least $82 million over the remaining 10 years of the plant's operating license.

     The Vermont Yankee nuclear power plant, which provides more than one-third of the Company's power supply, had a scheduled refueling outage in late April - May 2001; that outage was 11 days shorter than budgeted. The previous refueling outage began in late October 1999 and the plant returned to service in early December 1999. The 1998 refueling outage (March 21-June 3) extended 26 days beyond the scheduled 49 days. The next scheduled refueling outage is October 2002.

     In May 2002, Vermont Yankee had a mid-cycle outage, starting May 11 and ending May 23, in order to repair defective fuel rods. The Company requested and received PSB approval of an Accounting Order to defer incremental capacity and replacement energy costs related to the mid-cycle outage. In the second quarter of 2002, the Company deferred approximately $3.8 million related to the incremental capacity and replacement energy costs resulting from the May 2002 Vermont Yankee mid-cycle outage.

     On August 6, 1997, the Maine Yankee nuclear power plant was prematurely retired from commercial operation. The Company relied on Maine Yankee for less than 5% of its required system capacity. The decommissioning effort continues per project plans. The total expected decommissioning costs for Maine Yankee are $536.0 million in 1998 dollars. The original decommissioning contractor, Stone and Webster, filed for bankruptcy and, in January 2002, Maine Yankee and Federal Insurance agreed on a settlement of the pending litigation arising from contract performance when Stone and Webster went into bankruptcy. A settlement payment of $44.0 million has been deposited into the Maine Yankee Decommissioning Trust Fund. In the second quarter of 2002, the State of Maine withdrew from Texas compact (planned low-level waste facility in Texas) due to the 1997 closure of Maine Yankee and the inability of the State of Texas to build the disposal facility in a timely manner. Maine Yanke e believes that its withdrawal from the compact is justified but cannot predict with certainty if this will be challenged. Future payments for the closing, decommissioning and recovery of the remaining investment in Maine Yankee, including the insurance settlement and withdrawal from the Texas Compact are currently estimated to be approximately $458.6 million; the Company's share is expected to be approximately $9.2 million to be paid over the period 2002 through 2008.

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     On December 4, 1996, the Connecticut Yankee nuclear power plant was prematurely retired from commercial operation. The Company relied on Connecticut Yankee for less than 3% of its required system capacity. Connecticut Yankee continues to decommission the site. Connecticut Yankee reached a settlement with the FERC and the intervenors that allows for the cost recovery of the total expected decommissioning costs now estimated at $569.0 million in January 2000 dollars, as well as other appropriate costs of service. The settlement rates became effective September 1, 2000, following the FERC order of July 26, 2000. Connecticut Yankee is required to commence a new filing before the FERC no later than July 1, 2004 to review the status of decommissioning expenditures, the expected remaining decommissioning costs and their collections, and other appropriate issues. Future payments for the closing, decommissioning and recovery of the remaining investment in Connecticut Yankee are currently estimated to be approximately $226.6 million; the Company's share is expected to be approximately $4.5 million to be paid over the period 2002 through 2007.

     In 1992, the Yankee Atomic nuclear power plant was retired from commercial operation. The Company relied on Yankee Atomic for less than 1.5% of its system capacity. As of July 2000, Yankee Atomic had collected from its sponsors sufficient funds, based on a current forecast, to complete the decommissioning effort and to recover all other FERC-approved costs of service. Therefore, Yankee Atomic discontinued billings to its sponsors pending the need to increase or decrease the funds available for the completion of its financial obligations, including decommissioning. Such a change would require a FERC review and approval. Yankee Atomic is decommissioning the site as planned.

     Currently, costs billed to the Company by Maine Yankee and Connecticut Yankee, including a provision for ultimate decommissioning of the units, are being collected from the Company's customers through existing retail and wholesale rate tariffs. As of December 31, 2000, the Company completed its obligation for decommissioning costs based on current estimates related to Yankee Atomic. The Company's share of remaining costs with respect to Maine Yankee and Connecticut Yankee's decisions to discontinue operation were estimated to be $8.7 million and $4.1 million, respectively, at June 30, 2002. These amounts are subject to ongoing review and revisions and are reflected in the accompanying Consolidated Balance Sheet both as regulatory assets and nuclear dismantling liabilities (current and non-current).

     The decision to prematurely retire these nuclear power plants was based on economic analyses of the costs of operating them compared to the costs of closing them and incurring replacement power costs over the remaining period of the plants' operating licenses. This would have the effect of lowering costs to customers. The Company believes that based on the current regulatory process, its proportionate share of Maine Yankee, Connecticut Yankee and Yankee Atomic decommissioning costs will be recovered through the regulatory process and, 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, financial condition or cash flow.

     The Company is responsible for paying its entitlement percentage of decommissioning costs for Connecticut Yankee, Maine Yankee and Yankee Atomic, as well as its joint-ownership percentage of decommissioning costs for Millstone Unit #3. The staff of the Securities and Exchange Commission has questioned certain current accounting practices of the electric utility industry, including the Company, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations in financial statements of electric utilities. In August 2001, the Financial Accounting Standards Board 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 in the period i n which it is incurred. The Company has identified potential retirement obligations associated with the decommissioning of its nuclear facilities, but has not yet completed its assessment. This statement is effective for the Company on January 1, 2003. The Company has not yet quantified the impacts, if any, of adopting SFAS No. 143 on its financial statements.

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

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appointed purchasing agent who purchases and redistributes the power to all Vermont utilities pursuant to PSB Rule 4.100. Under these long-term contracts, for the six months ended June 30, 2002, the Company received 116,029 mWh of which 86,272 mWh was allocated to the Company by the Purchasing Agent, VEPP Inc. and 18,288 mWh was purchased by Connecticut Valley, the Company's wholly owned New Hampshire subsidiary, from a waste-to-energy electric generating facility owned by Wheelabrator Claremont Company, L.P.

     On August 3, 1999, the Company, GMP, Citizens Utilities and all of Vermont's 15 municipal utilities filed a petition with the PSB requesting modification of the contracts between the IPPs and the state-appointed purchasing agent. The petition outlined seven specific elements that, if implemented, would reduce purchase power costs and reform these contracts for the benefit of consumers. On September 3, 1999, the PSB opened a formal investigation in Docket No. 6270 regarding these contracts as requested by the Petition. Shortly thereafter, Citizens Utilities, Hardwick Electric Department and Burlington Electric Department notified the PSB that they were withdrawing from the Petition but would participate in the case as non-moving parties. In a separate action before the Chittenden County Superior Court brought by several IPP owners, GMP's full participation in this PSB proceeding was enjoined and that injunction has since been appealed to and affirmed by the Vermont Supreme Court.

     On November 22, 2000, the IPPs filed dispositive motions in Docket No. 6270, urging the PSB to declare that it lacks jurisdiction to grant relief sought by the Company's Petition. On September 18, 2001, the PSB issued an Order regarding jurisdiction finding that it has jurisdiction to consider the relief sought under the Petition but that it is precluded from issuing orders reducing the lengths of a Purchasing Agent contract or requiring buy-outs or buy-downs.

     The IPPs also filed a related proceeding in the Washington County Superior Court contending that the PSB rules pertaining to IPPs, which the utilities have relied upon, in part, in their Petition before the PSB, contains a so-called "scrivener's error." By motion filed in the Superior Court in September 2000, the IPPs sought summary judgement in this action. On January 19, 2001, the Washington County Superior Court dismissed the IPPs' action, which the IPPs appealed to the Vermont Supreme Court. The IPPs also asked the Vermont Supreme Court to stay the proceeding before the PSB pending the outcome of their appeal. By order dated April 5, 2001, the Vermont Supreme Court denied the IPPs' request for a stay. By Order dated April 22, 2002, the Vermont Supreme Court denied the IPP's appeal. By Motion of May 3, 2002, the IPPs sought re-argument before the Vermont Supreme Court in this matter, which request was also rejected by the Court.

     The Company participated in various legal proceedings and regulatory filings related to the Docket throughout 2002 and 2001. In September 2001, the Petitioners and the IPPs agreed to enter into a settlement discussion and on September 28, 2001 filed a Stipulation for Stay requesting that further proceedings in the Docket be stayed to provide the parties an opportunity to engage in settlement negotiations. On October 18, 2001, the PSB Hearing Officer issued an order granting the Stipulation for Stay.

     After several extensions, on January 28, 2002, the Petitioners and the IPPs filed a Memorandum of Understanding with the PSB which, if approved, establishes a comprehensive settlement to the issues in Docket No. 6270. The Memorandum of Understanding would provide:

1. power cost reductions nominally worth approximately $11.0 million to $14.0 million over ten years;
2. the agreement of the IPPs to support efforts before the Vermont General Assembly and the PSB to authorize securitization (which efforts have resulted in the enactment of Act No. 145 of the 2002 General Assembly which authorizes the issuance of securitization orders by the PSB and creates a new state entity to issue mitigation bonds to pay for the buydowns of certain of the Purchasing Agent's IPP contracts) and to negotiate for the buy-out and buy-down of the IPP contracts with the goal of achieving additional power cost savings; and
3. a global resolution of various related issues.

     At this time, proceedings are continuing in PSB Docket No. 6270 to consider the Memorandum of Understanding. Technical Hearings were held before the PSB's Hearing Officer on May 1 and 2, 2002. At the hearings, certain of the non-petitioning Vermont utilities and the DPS argued that all Vermont electric utility customers should be permitted to share in the benefits arising under the Memorandum of Understanding. Subject to this and other conditions, the DPS argued that the Memorandum of Understanding should be approved. A decision is expected by the end of 2002.

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

     The Company is currently in the process of relicensing or preparing to relicense eight separate hydroelectric projects under the Federal Power Act. These projects, some of which are grouped together under a single license, represent approximately 29.9 mW, or about 66.8% of the Company's total hydroelectric nameplate capacity. In the new licenses, the FERC is expected to impose conditions designed to address the impact of the projects on fish and other environmental concerns. The Company is unable to predict the specific impact of the imposition of such conditions, but capital expenditures and operating costs are expected to increase in the short term to meet these licensing obligations and net generation from these projects will decrease in future periods.

     Peterson Dam: The Company has worked with environmental groups and the State of Vermont since 1998 to develop a plan to relicense Peterson Dam, a 6.2 mW hydroelectric station on the Lamoille River. The Vermont Natural Resources Council ("VNRC") has proposed removal of the dam, a 1948 hydro-generating unit that produces power to energize approximately 3,000 homes per year.

     In August 2000, talks broke down, and the VNRC called publicly for removal of the dam. The Company has initiated broader discussions with VNRC, Trout Unlimited, the Vermont Agency of Natural Resources and other parties, related to the economic, reliability and environmental issues that Peterson's removal would create. Negotiations between the parties are continuing.

Production and transmission  The increase of $1.3 million for the second quarter and $0.8 million in the first half of 2002 compared to 2001 resulted mostly from higher ISO-New England transmission congestion charges and lower production costs in 2001.

Other operation expenses The decrease of approximately $1.6 million for the second quarter and $2.4 million for the first half of 2002 versus 2001 resulted primarily from a reduction of environmental reserves and decreased conservation and load management costs in 2002, as a result of the Vermont Energy Efficiency Utility, partially offset by an increase in bad debt reserves due to certain bankruptcies.

Maintenance expenses  The $0.3 million decrease in maintenance expense in the second quarter and $1.0 million in the first half of 2002 compared to 2001 is primarily due to lower storm restoration costs and lower costs associated with the Company's share of Millstone Unit #3.

Other taxes, principally property taxes  Other taxes increased by $0.4 million in the second quarter and $0.5 million in the first half of 2002, primarily due to increases in property taxes, resulting from Vermont's Act 60 assessments.

Income taxes  Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences. Income taxes decreased in the second quarter and first half of 2002 compared to 2001 due to changes in permanent differences for the periods.

Other income and deductions  Other income and deductions increased $8.3 million for the second quarter and
$7.8 million in the first half of 2002 compared to 2001 mostly due a one-time pre-tax write-off of $9.0 million of certain regulatory assets in June 2001 related to the Company's June 26, 2001 rate case settlement, offset by the Company's decision to discontinue Eversant's efforts to pursue non-regulated business opportunities in the first quarter of 2002, lower Catamount equity losses, lower interest and dividend income and higher life insurance expense in the second quarter due to market fluctuations.

Other interest expense  The $0.5 million decrease in Other interest expense in the second quarter and $0.4 million decrease in the first half of 2002 compared to 2001 was due to the settlement of an IRS interest expense accrual previously recorded in the fourth quarter of 2001.

Other adjustments  The $0.1 million decrease in Other Adjustments in the second quarter of 2002 versus 2001 resulted primarily from an adjustment to retained earnings related to stock option exercises.

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     The Company's liquidity is primarily affected by the level of cash generated from operations and the funding requirements of its ongoing construction programs. The Company's capital expenditure projections for the years 2002 through 2006 total approximately $90.0 million; these projections are revised from time-to-time to reflect changes in conditions. Net cash flow provided by operating activities generated $16.8 million and $8.1 million of cash for the six months ended June 30, 2002 and 2001, respectively.

     The Company ended the first six months of 2002 with cash and cash equivalents of $48.0 million, an increase of $2.5 million from the beginning of the year. The increase in cash for 2002 was the result of $16.8 million provided by operating activities, offset by $7.1 million used for investing activities and $7.2 million used for financing activities.

     Operating Activities Net income and depreciation, deferred income taxes and investment tax credits provided cash of $18.1 million. Approximately $1.3 million of cash was used by working capital and other operating activities.

     Investing Activities Construction and plant expenditures used cash of approximately $6.4 million and $0.7 million was used for non-utility investments, primarily related to Catamount's investment in Gauley River Power Partners, L.P. ("Gauley River").

     Financing Activities Dividends paid on common stock were $5.1 million, while preferred stock dividends were $0.8 million. The retirement of preferred stock required $1.0 million and the pay down of capital lease obligations required $0.6 million. Net long-term debt used $0.1 million and the sale of common stock from the Company's Treasury shares provided $0.4 million.

     The 8.3% Dividend Series Preferred Stock is redeemable at par through a mandatory sinking fund in the amount of $1.0 million per annum and, at its option, the Company may redeem at par an additional non-cumulative $1.0 million per annum. The Company paid the mandatory sinking fund payment in the amount of $1.0 million in the first quarter of 2002. The Company is in the process of repurchasing $3.0 million of its 8.3% series preferred stock from the Company's preferred shareholders, and expects to complete the transaction in the third quarter of 2002.

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

     The Company's long-term debt arrangements contain financial and non-financial covenants. At June 30, 2002, the Company was in compliance with all debt covenants related to its various debt agreements.  Substantially all Vermont utility property and plant is subject to liens under the First and Second Mortgage Bonds.

     In 1998, Catamount replaced its $8.0 million credit facility with a $25.0 million revolving credit/term loan facility, maturing November 2006, which provides for up to $25.0 million in revolving credit loans and letters of credit, of which $21.3 million was outstanding at June 30, 2002. The interest rate is variable, prime-based. Catamount's assets secure the facility. Based on total outstanding debt of $21.5 million at June 30, 2002, including Catamount's office building mortgage, the aggregate amount of Catamount's long-term debt maturities are $3.4 million, $3.2 million, $4.2 million, $5.0 million and $5.7 million for the years 2002 through 2006, respectively. Catamount's long-term debt contains financial and non-financial covenants. At March 31, 2002, Catamount was in compliance with all covenants under the revolver except that Catamount was not in compliance with the projected minimum coverage ratio. The Lender did not declare Catamount in default since the nonc ompliance was due to the timing of the sale or refinancing of certain Catamount equity investments anticipated to close prior to the end of 2002. At June 30, 2002, Catamount was in compliance with all covenants under the revolver.

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     In 1999, SmartEnergy Water Heating Services, Inc. ("SEWHS"), a wholly owned subsidiary of Eversant, secured a $1.5 million, seven-year term loan with Bank of New Hampshire with an outstanding balance of $1.0 million at June 30, 2002. The interest rate is fixed at 9.5% per annum. Based on outstanding debt at June 30, 2002, the aggregate amount of SEWHS's long-term debt maturities are $0.2 million, $0.2 million, $0.2 million, $0.2 million and $0.2 million for the years 2002 through 2006, respectively. SEWHS's long-term debt contains financial and non-financial covenants. At June 30, 2002, SEWHS was in compliance with all debt covenants related to its various debt agreements.

     Current credit ratings of the Company's securities by Standard & Poor's and Fitch IBCA ("Fitch") remain as follows:

1. Outlook: Stable
2. Outlook: Stable

     The Company cannot assure that its business will generate sufficient cash flow from operations or that future borrowing will be available to the Company in an amount sufficient to enable the Company to pay its indebtedness, including the $75.0 million Second Mortgage Bonds, when due or to fund its other liquidity needs. The Company's ability to repay its indebtedness is, to a certain extent, subject to general economic, financial, competitive, legislative, regulatory, weather and other factors that are beyond its control. The type, timing and terms of future financing that the Company may need will be dependent upon its cash needs, the availability of refinancing sources and the prevailing conditions in the financial markets. The Company cannot guarantee that financing sources will be available to the Company at any given time or that the terms of such sources will be favorable.

     Catamount Resources Corporation was formed for the purpose of holding the Company's subsidiaries that invest in non-regulated business opportunities. Catamount, a subsidiary of Catamount Resources Corporation, invests through its wholly owned subsidiaries in non-regulated energy generation projects in North America and Western Europe. Through its wholly owned subsidiaries, Catamount has interests in ten operating independent power projects located in Glenns Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont; Thetford, England; Hopewell, Virginia; Thuringen, Germany; Mecklenburg-Vorpommern, Germany; Fort Dunlop, England; and Summersville, West Virginia.

     In 2001, Catamount undertook a comprehensive strategic review of its operations. As a result, Catamount has refocused its efforts from being an investor in late-stage renewable energy to being primarily focused on developing, owning and operating wind energy projects. As a result of the change in strategic direction, Catamount is currently pursuing the sale of certain of its interests in non-wind electric generating assets. Depending on prices, capital and other requirements, Catamount will also entertain offers for the purchase of any of its remaining non-wind electric generating assets. Proceeds from the sales will be used to either pay down the outstanding loan balance or be reinvested in the development of new wind projects as well as the acquisition of existing wind projects. Additionally, Catamount is seeking investors and partners to co-invest with Catamount in the development, ownership and acquisition of projects, which will be financed by equity and non-recours e debt. Management cannot predict the timing or outcome of potential future asset sales or whether this new strategy will be successful.

     Catamount has projects under development in the United States and Western Europe. In June 2001, Catamount established Catamount Development GmbH, a German corporate entity, 100% owned by Catamount Heartlands Corp., a wholly owned subsidiary of Catamount. The company was formed to hold Catamount's interests in German "greenfield" development projects or projects that would be purchased by Catamount in early- to mid-stage development. In February 2002, Catamount entered into a joint venture agreement with North American Renewables Corp., a subsidiary of Group EHN-Iberdrola, named New England Windpower. The purpose of the joint venture is to develop, own and operate wind projects in New England. Additionally, in February 2002, Catamount entered into a joint development agreement with force9energy Ltd. of England to develop wind projects in England, Scotland and Wales.

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     At December 31, 2001, the Company made the decision to actively market for sale its project interest in Gauley River. In the fourth quarter, Catamount recorded an after-tax impairment charge to earnings of $1.4 million associated with its interests in Gauley River. The impairment was based on bids received from third parties, less estimated costs to sell. Catamount entered into a Purchase and Sale Agreement, dated June 30, 2002, with a third party, for the sale of its Gauley River investment interests. The sale is subject to the approval of the FERC and the Hart-Scott Rodino notification and various consents. Catamount expects the sale to be finalized in the fourth quarter of 2002. The Company expects the proceeds from the sale to approximate the net book value of its investment in Gauley River.

     The final $1.0 million payment pursuant to the settlement agreement with Black & Veatch Construction, Inc. for cost overruns associated with the construction of Summersville Hydroelectric Power Station, owned by Gauley River, was made on March 31, 2002.

     Although Catamount has a controlling interest in Gauley River, this investment has not been consolidated in the accompanying financial statements since it is Management's intention to sell this project, and therefore, control is considered temporary. For equity accounting purposes, the Gauley River investment is treated as 100% ownership. The Gauley River project has total assets of $56.9 million and total liabilities of $46.7 million at June 30, 2002.

     Catamount's Fibrothetford Limited ("Fibrothetford") equity investment has been reduced to zero as a result of losses incurred to date. Continuing equity losses have been applied as a reduction to Catamount's note receivable balance from Fibrothetford. Catamount will also reserve against future interest income on the note receivable, which is expected to be approximately $1.7 million over the next twelve months.

     At December 31, 2001, Catamount's Fibrothetford investment was classified as a current equity investment. Catamount is actively marketing its interests in Fibrothetford; Management, however, cannot predict whether a sale will ultimately occur. In the fourth quarter of 2001, Catamount recorded an after-tax impairment charge to earnings of $3.2 million. Also, a valuation allowance for the $2.2 million deferred tax asset was recorded. The impairment charge was based on review of expected future cash flows and expected market value of Catamount's interest given the project's current financial condition.

     Fibrothetford is seeking to refinance its debt and anticipates the earliest a refinancing can occur is 2003. In order for the refinancing to be successful in 2003, Fibrothetford must either be exempted from or be able to comply with the new emissions standards established by the European Union effective December 31, 2005. Management cannot predict whether Fibrothetford will ultimately be successful in the refinancing of its debt.

     In the fourth quarter 2001, Catamount recorded impairment charges for all of its interests in the Rupert and Glenns Ferry projects for a total after-tax charge of $3.0 million. This charge reduced the value of these investments to zero. The impairment charges were the result of the deteriorating financial condition of the projects' steam hosts that are essential to the projects' Qualifying Facility status and long-term viability. In June 2002, the steam host for Rupert sold its manufacturing operations and on June 25, 2002, Rupert entered into a new thermal energy service agreement with the new steam host. As a result of the steam host restructuring, Catamount reassessed its investment in Rupert and reinstated the equity method of accounting for its investment. In July 2002, the steam host for Glenns Ferry sold its manufacturing operations and on July 9, 2002, Glenns Ferry entered into a new thermal energy service agreement with the new steam host. In May 2002, Rupert a nd Glenns Ferry were issued an Events of Default notice by their lender. The steam host restructurings cured most of the events of default identified in the Events of Default notices. The remaining defaults should be cured over the next several months.

     In August 2002, Catamount began to actively market for sale its project interests in Rupert and Glenns Ferry.

     Catamount's after-tax earnings were $0.5 million and $0.2 million for the second quarter of 2002 and 2001, respectively, and $0.9 million and $0.5 million for the first six months of 2002 and 2001, respectively.

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     Eversant, also a subsidiary of Catamount Resources Corporation, invests in unregulated energy and service-related businesses. Eversant had a 12.1% ownership interest, on a fully diluted basis, in HSS as of June 30, 2002. HSS establishes a network of affiliate contractors who perform home maintenance repair and improvements via membership. HSS began operations in 1999 and is subject to risks and challenges similar to a company in the early stage of development. HSS launched a Commercial Services division in 2001, which meets the needs of small businesses, building owners and property managers. In May 2001, Eversant entered into a convertible loan agreement with HSS and Jupiter Capital ("Jupiter"). Under the agreement, Eversant loaned HSS $2.0 million and Jupiter loaned HSS $5.0 million, which, along with current debt balances and accrued interest, was converted to preferred securities when HSS received an additional cash investment from Jupiter in August 2001. In Septem ber 2001, Eversant recorded a $1.2 million after-tax write-down of its investment in HSS to fair value. Eversant has previously recorded losses of $9.0 million related to its investment in HSS. At year end, Jupiter committed, based upon continued satisfactory operating progress, to provide an additional $5.0 million in funding to the business over time. The first $1.0 million was invested in December 2001 and Jupiter received options to acquire up to an aggregate of $4.0 million in preferred securities. Jupiter has invested a total of $4.0 million in 2002, and predicts that an additional $2.0-$3.0 million in funding above the $5.0 million may be required and they are currently talking to other parties about providing this capital. As of July 2002, Eversant's fully diluted ownership position in HSS, after the $5.0 million Jupiter investment is 12.0%.

     Eversant's share of the HSS losses for 2002 was zero as the Company's equity investment was reduced to zero as a result of losses incurred to date. As of June 30, 2002, Eversant has a preferred equity investment in HSS of $1.4 million, recorded at estimated fair value.

     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 markets and sells its SmartDrive Control product. The arbitration concerned the Company's claim that Westfalia-Surge had not conducted itself in accordance with the exclusive distributorship agreement between the parties. On January 28, 2002, the Company received an adverse decision related to the arbitration proceeding with Westfalia-Surge. The Company does not expect a material liability related to the decision and is currently in discussions with Westfalia-Surge regarding this matter.

     The Company has decided to discontinue Eversant's efforts to pursue non-regulated business opportunities.

Overall, Eversant had consolidated after-tax earnings of $0.2 million and after-tax losses of $0.1 million for the second quarter of 2002 and 2001, respectively, and after-tax losses of $0.4 million and $0.2 million for the first six months of 2002 and 2001, respectively.

     The Company recognizes that adequate and timely rate relief is necessary if it is to maintain its financial strength, particularly since Vermont regulatory rules do not allow for changes in purchased power and fuel costs to be automatically passed on to consumers through rate adjustment clauses. The Company intends to continue its practice of periodically reviewing costs and requesting rate increases when warranted. The Company currently plans, absent any unforeseen developments, to refrain from changing rates for its Vermont utility customers until 2006.

     See Notes 2 and 5 to the Consolidated Financial Statements for information related to Vermont Retail Rates.

     The electric utility industry is in a period of transition that in some cases has resulted in a shift away from ratemaking based on cost of service and return on equity to more market-based rates with energy sold to customers by competing retail energy service providers. Many states, including New Hampshire, where the Company does business, are exploring new mechanisms to bring greater competition, customer choice and market influence to the industry while retaining the public benefits associated with the current regulatory system. Recent events, including those related to restructuring in California, uncertainties concerning the operations of the wholesale markets in New England, and the demise of major wholesale power marketing companies such as Enron, have resulted in a slowdown of the restructuring process in Vermont.

     There have been three primary sources of Vermont governmental activity in attempting to restructure the electric industry in Vermont: 1) the Governor's Working Group, created by the Governor of Vermont; 2) the PSB's Docket No. 6140 through which the PSB considered proposals to restructure committed utility power supply arrangements; and 3) the PSB's Docket No. 6330, through which the PSB considered the establishment of policies and procedures