10-Q

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549

Form 10-Q

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

For the quarterly period ended     September 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 October 31, 2002 there were outstanding 11,720,994 shares of Common Stock, $6 Par Value.

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Form 10-Q - 2002

Table Of Contents

		Page
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Condensed Consolidated Statement of Income and Retained Earnings for      the three and nine months ended September 30, 2002 and 2001	3
	Condensed Consolidated Balance Sheets as of September 30, 2002      and December 31, 2001	4
	Condensed Consolidated Statement of Cash Flows for the nine months      ended September 30, 2002 and 2001	5
	Notes to Condensed Consolidated Financial Statements	6
Item 2.	Management's Discussion and Analysis of Financial Condition and   Results of Operations	18
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	35
Item 4.	Controls and Procedures	38
PART II	OTHER INFORMATION	39
SIGNATURES		40
CERTIFICATIONS PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT		41
EXHIBIT INDEX		43

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements

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

	Three Months Ended September 30		Nine Months Ended September 30
	2002	2001	2002	2001
Operating Revenues	$75,733	$75,135	$224,111	$227,049
Operating Expenses
Operation
Purchased power	33,273	36,070	107,150	110,444
Production and transmission	6,599	6,473	19,456	18,456
Other operation	11,336	10,029	31,094	32,152
Maintenance	4,076	4,373	12,288	13,575
Depreciation	4,059	4,261	12,401	12,774
Other taxes, principally property taxes	3,232	2,904	9,783	8,915
Taxes on income	3,988	3,419	9,808	9,482
Total operating expenses	66,563	67,529	201,980	205,798
Operating Income	9,170	7,606	22,131	21,251
Other Income and Deductions
Equity in earnings of affiliates	2,228	699	3,555	2,057
Allowance for equity funds during construction	(13)	11	40	44
Other income (deductions), net	(2,623)	(2,108)	(2,137)	(9,406)
Benefit for income taxes	428	868	463	4,043
Total other income and deductions, net	20	(530)	1,921	(3,262)
Total Operating and Other Income	9,190	7,076	24,052	17,989
Interest Expense
Interest on long-term debt	3,164	3,228	9,430	9,715
Other interest	164	107	27	325
Allowance for borrowed funds during construction	7	(6)	(20)	(22)
Total interest expense, net	3,335	3,329	9,437	10,018
Net Income Before Extraordinary Charge	5,855	3,747	14,615	7,971
Extraordinary Charge net of taxes	-	182	-	182
Net Income	5,855	3,565	14,615	7,789
Retained Earnings at Beginning of Period	72,231	76,975	69,170	78,423
Retained Earnings Before Dividends	78,086	80,540	83,785	86,212
Cash Dividends Declared
Preferred Stock	380	424	1,187	1,272
Common Stock	0	2,543	5,132	7,627
Total Dividends Declared	380	2,967	6,319	8,899
Other Adjustments	102	(22)	342	238
Retained Earnings at End of Period	$ 77,808	$ 77,551	$ 77,808	$  77,551
Earnings Available For Common Stock	$ 5,475	$3,141	$ 13,428	$6,517
Average Shares of Common Stock Outstanding - Basic	11,697,336	11,554,588	11,660,792	11,544,227
Average Shares of Common Stock Outstanding - Diluted	11,938,694	11,554,588	11,909,428	11,786,776
Earnings Per Basic and Diluted Share of Common Stock - Basic	$.47	$.27	$1.15	$.56
Earnings Per Basic and Diluted Share of Common Stock - Diluted	$.46	$.27	$1.13	$.55
Dividends Paid Per Share of Common Stock	$.22	$.22	$.66	$.66

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

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

	September 30	December 31
	2002	2001
	(unaudited)
Assets
Utility Plant, at original cost	$497,193	$490,137
Less accumulated depreciation	206,364	198,087
	290,829	292,050
Construction work-in-progress	12,306	15,727
Nuclear fuel, net	1,224	852
Net utility plant	304,359	308,629
Investments and Other Assets
Investments in affiliates, at equity	25,906	23,823
Non-utility investments	33,167	38,514
Non-utility property, less accumulated depreciation	2,208	2,401
Total investments and other assets	61,281	64,738
Current Assets
Cash and cash equivalents	50,002	45,491
Special deposits	8	7
Accounts receivable, less allowance for uncollectible accounts             ($1,233 in 2002 and $2,071 in 2001)	21,749	21,951
Unbilled revenues	13,397	16,404
Materials and supplies, at average cost	3,895	4,167
Prepayments	2,546	3,676
Non-utility investments	15,902	11,029
Other current assets	5,146	5,408
Total current assets	112,645	108,133
Regulatory Assets	23,405	32,403
Other Deferred Charges	16,024	7,771
Total Assets	$517,714	$521,674
Capitalization and Liabilities
Capitalization
Common stock, $6 par value, authorized 19,000,000 shares;              issued 11,785,848 shares; outstanding 11,712,095	$70,715	$70,715
Other paid-in capital	47,937	47,634
Accumulated other comprehensive income	(267)	(623)
Deferred compensation plans - employee stock ownership plans	(1,094)	(1,097)
Treasury stock (73,753 and 175,165 shares, respectively, at cost)	(975)	(2,285)
Retained Earnings	77,808	69,170
Total Common Stock Equity	194,124	183,514
Preferred and preference stock	8,054	8,054
Preferred stock with sinking fund requirements	11,000	15,000
Long-term debt	151,857	159,771
Capital lease obligations	12,119	12,897
Total capitalization	377,154	379,236
Current Liabilities
Current portion of preferred stock	1,000	1,000
Current portion of long-term debt	13,940	7,225
Accounts payable	3,546	4,796
Accounts payable - affiliates	12,492	12,092
Accrued income taxes	0	74
Dividends declared	0	2,978
Nuclear decommissioning costs	2,069	2,298
Other current liabilities	19,956	19,739
Total current liabilities	53,003	50,202
Deferred Credits
Deferred income taxes	40,880	38,828
Deferred investment tax credits	5,365	5,658
Nuclear decommissioning costs	10,977	12,826
Other deferred credits	30,335	34,924
Total deferred credits	87,557	92,236
Commitments and Contingencies
Total Capitalization and Liabilities	$517,714	$521,674

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

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in thousands)
(Unaudited)

	Nine Months Ended       September 30
	2002	2001
Cash Flows Provided (Used) By:
Operating Activities
Net income	$14,615	$7,789
Adjustments to reconcile net income to net cash provided by operating activities
Extraordinary Charge	-	182
Equity in earnings of affiliates	(3,555)	(2,057)
Dividends received from affiliates	1,387	2,050
Equity in earnings from non-utility investments	(8,233)	(3,900)
Distribution of earnings from non-utility investments	6,347	2,737
Depreciation	12,401	12,774
Regulatory asset write-off	-	9,000
Investment write-down	2,740	1,963
Vermont Yankee fuel rod maintenance deferral	(3,767)	-
Vermont Yankee post sale costs deferral	(5,468)	-
Amortization of capital leases	817	817
Deferred income taxes and investment tax credits	1,990	(5,399)
Net (deferral) and amortization of nuclear replacement            energy and maintenance costs	3,653	(3,984)
Amortization of conservation and load management costs	1,662	2,590
Decrease in accounts receivable and unbilled revenues	3,458	7,842
Decrease in accounts payable	(759)	(6,606)
Decrease in accrued income taxes	(154)	(1,263)
Change in other working capital items	1,818	(5,119)
Other, net	(291)	3,369
Net cash provided by operating activities	28,661	22,785
Investing Activities
Construction and plant expenditures	(9,366)	(10,674)
Conservation and load management expenditures	(150)	(413)
Return of capital	200	140
Utility investments	(449)	-
Non-utility investments	(253)	(7,697)
Other investments, net	(105)	(414)
Net cash used for investing activities	(10,123)	(19,058)
Financing Activities
Proceeds from issuance of long-term debt	-	6,867
Repayment of long-term debt	(1,198)	(148)
Retirement of preferred stock	(4,000)	-
Common and preferred dividends paid	(9,303)	(8,464)
Reduction in capital lease obligations	(817)	(817)
Sale of treasury stock - dividend reinvestment program	875	-
Sale of treasury stock - stock options	416	627
Other	-	(22)
Net cash used by financing activities	(14,027)	(1,957)
Net Increase In Cash and Cash Equivalents	4,511	1,770
Cash and Cash Equivalents at Beginning of Period	45,491	47,986
Cash and Cash Equivalents at End of Period	$50,002	$49,756
Supplemental Cash Flow Information
Cash paid during the year for:
Interest (net of amounts capitalized)	$9,357	$10,307
Income taxes (net of refunds)	$7,752	$12,559
The accompanying notes are an integral part of the condensed consolidated financial statements

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     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 nine months ended September 30, 2002 are not necessarily indicative of the results that may be expected for the twelve months ended 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 Dece mber 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.

NOTE 2 - REGULATORY ACCOUNTING

     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:

	September 30	December 31
	2002	2001
Regulatory assets
Conservation and load management (a)	$1,634	$4,633
Restructuring costs	74	59
Nuclear refueling outage costs (a)	792	4,445
Income taxes (b)	6,538	6,770
Dismantling costs (c):
Maine Yankee nuclear power plant	9,138	10,612
Connecticut Yankee nuclear power plant	3,908	4,513
Unrecovered plant and regulatory study costs	1,153	1,310
Other regulatory assets	168	61
Subtotal Regulatory assets	$23,405	$32,403
Other deferred charges
Vermont Yankee fuel rod maintenance deferral	$3,768	-
Vermont Yankee sale costs	5,468	-
Hydro-Quebec Sellback #3 derivative	1,038	$1,038
Subtotal Other deferred charges	$10,274	$1,038
Other deferred credits
Hydro-Quebec ice storm settlement	-	$1,607
Other regulatory liabilities	$606	620
Subtotal Other deferred credits	$606	$2,227
Net Regulatory Assets	$33,073	$31,214
(a)  The Company earns a return on unamortized Conservation and Load Management costs and        replacement energy and maintenance costs related to scheduled nuclear refueling outages.
(b)  The net regulatory asset related to the adoption of SFAS No. 109 is recovered through tax        expense in the Company's cost of service generally over the remaining lives of the related property.
(c)  Recovery for the unamortized dismantling costs for Connecticut Yankee and Maine Yankee is       provided without a return on investment through 2007 and 2008, respectively.

     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

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of 2001, Vermont Yankee and Millstone Unit #3 had scheduled refueling outages and in September 2002, Millstone Unit #3 began another scheduled refueling outage. In the third quarter of 2002, the Company discontinued deferring and amortizing costs related to Vermont Yankee's scheduled refueling outages due to the July 31, 2002 sale of the plant. 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 Condensed Consolidated Balance Sheet. See Note 4, Vermont Yankee - Operations, for additional information related to the Accounting Order.

     In the third quarter of 2002, based on an approved Accounting Order from the PSB, the Company deferred approximately $5.5 million related to costs associated with the sale of Vermont Yankee including increased purchased power costs under the Purchased Power Agreement. 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 Condensed Consolidated Balance Sheet. See Note 4, Vermont Yankee - Sale, for additional information related to the Accounting Order.

     The Company records as regulatory liabilities, costs that have been recovered by the Company but have not yet been included in rates. On October 4, 2002, the PSB issued an Order approving the Company's proposal for reducing certain regulatory assets by $2.0 million through application of regulatory liabilities related to the remaining Hydro-Quebec settlement and the ongoing Millstone Unit #3 decommissioning non-payments. Although the Company is recovering the Millstone Unit #3 decommissioning costs in rates, its payments for decommissioning have ceased. In the third quarter of 2002, based on the PSB Order, the Company reduced certain of its regulatory assets related to Conservation and Load Management by $2.0 million. The Company will account for the ongoing Millstone Unit #3 decommissioning non-payments as a regulatory liability, with carrying charges, to be addressed in the Company's next rate proceeding. The remaining regulatory liabilities are included in Other defer red credits on the Condensed Consolidated Balance Sheets.

NOTE 3 - INVESTMENTS IN AFFILIATES

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

Vermont Yankee Nuclear Power Corporation:

	Three Months Ended September 30		Nine Months Ended September 30
Earnings	2002	2001	2002	2001
Operating revenues	$48,534	$37,867	$134,030	$135,862
Operating income	$2,052	$3,105	$7,706	$9,187
Net income	$5,911	$1,641	$8,860	$4,765
Company's accrued equity in net income	$1,964	$521	$2,944	$1,493

     Vermont Yankee's revenues shown above include sales to the Company (reflected as purchased power expenses in the accompanying Condensed Consolidated Statement of Income) of $16.9 million and $12.1 million for the third quarter of 2002 and 2001, respectively, and $45.7 million and $42.6 million for the nine months of 2002 and 2001, respectively.

     In the first quarter of 2002, the Company's ownership percentage of VYNPC changed from 31.3 percent to 33.23 percent 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 Corporation ("Entergy"), however the Company continues to have a 33.23 percent 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 percent with two remaining secondary purchasers receiving a small percentage of the Company's entitlement as well. As a result of the sale, the Company no longer bears the operating costs and risks associated with running the plant or the costs and risks associated with the eventual decommissioning of the plant. See Note 4, Vermont Yankee - Sale, for more detail.

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Vermont Electric Power Company ("VELCO"):

	Three Months Ended September 30		Nine Months Ended September 30
Earnings	2002	2001	2002	2001
Transmission revenues	$5,012	$6,806	$16,808	$22,524
Operating income	$1,397	$712	$3,734	$2,250
Net income	$261	$230	$774	$782
Company's accrued equity in net income	$133	$135	$396	$435

     VELCO's revenues shown above include transmission services to the Company (reflected as production and transmission expense in the accompanying Condensed Consolidated Statement of Income) amounting to $2.6 million for the third quarters of 2002 and 2001, and $8.9 million and $7.7 million for the nine months of 2002 and 2001, respectively.

     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 can 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 Articles of Association, and adjust total equity ownership. On July 15, 2002, the FERC approved the transaction.

     In the third quarter of 2002, the Company acquired additional shares of VELCO's Class C common stock, in the amount of $0.5 million, however, the Company's control of VELCO will continue to be restricted. The Company's common stock ownership percentage in VELCO changed from 56.8 percent to 50.6 percent, as a result of VELCO's Class C common stock issuance, to provide capital to VELCO and realign equity ownership of VELCO, as close as possible to entitlement levels of VELCO's transmission services. The Company also owns 46.6 percent of VELCO's outstanding preferred stock, $100 par value.

     In the nine months of 2002 and 2001, the Company received $0.1 million and $0.1 million, respectively, from VELCO, related to the return of capital from VELCO's Class C preferred stock.

NOTE 4 - VERMONT YANKEE

Vermont Yankee - Sale

     On July 31, 2002, VYNPC completed the sale of its assets to Entergy. As part of the sale transaction, the Company agreed to contribute approximately $1.0 million in stockholder funds to the non-Vermont owners of the plant in order to provide parity for the non-Vermont owners assigning their share of the decommissioning fund to Entergy.

     The Company has a 33.23 percent equity interest in VYNPC, a Vermont-based corporation that will administer the purchase power contracts among the former plant owners and Entergy. Certain residual VYNPC costs will continue to be billed by VYNPC to its sponsors in addition to purchased power costs from Entergy. The Company also receives its 35 percent entitlement of Vermont Yankee output sold by Entergy to VYNPC under the purchased power agreements ("PPA") and two remaining secondary purchasers will continue receiving a small percentage of the Company's entitlement.

     Although the sale closed on July 31, 2002, the Company's distribution from the sale proceeds and final accounting for the sale are pending certain regulatory approvals and the resolution of certain closing items between the seller and purchaser. The Company expects its share of the Vermont Yankee sale proceeds to be distributed in 2003. Third quarter 2002 accounting related to the Vermont Yankee sale includes the following:

• The Company recorded a $0.6 million after-tax one-time expense related to a shareholder payment for the Company's contribution to the non-Vermont owners of the plant as described above. This one-time expense is included in Other Income and Deductions on the Company's Condensed Consolidated Statement of Income.

• The Company deferred approximately $3.2 million after-tax in the third quarter of 2002, based on an approved Accounting Order from the PSB. The Accounting Order authorizes the Company to defer the incremental costs that occur in 2002 in connection with the sale and increased purchased power costs under

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• the PPA contracts compared to costs if the Company had continued to own the plant. The purchased power contract between Entergy and Vermont Yankee is forecasted to lead to higher purchased power costs in the initial years of the contract with decreased costs in future years when compared to continued ownership of the plant. Also see Note 2, Regulatory Accounting.

• The Company recorded a $1.3 million after-tax reduction in purchased power expense and a $1.2 million after-tax increase in equity earnings from Vermont Yankee. The $2.5 million after-tax favorable impact was primarily due to state tax benefits now available to Vermont Yankee, which were passed on to the owners. The favorable impact is included in the Company's Condensed Consolidated Statement of Income.

Vermont Yankee - Operations: 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 May 2002 Vermont Yankee mid-cycle outage.

     Vermont Yankee accomplished a 21-day refueling outage between October 5 and October 27, 2002. Although the Company is no longer responsible for refueling outage costs, it remains responsible for procuring replacement energy during the outage and any other Vermont Yankee outages in the future. As such, the Company no longer defers or amortizes incremental capacity and replacement energy costs as it had done in the past. Under the PPA, the Company pays Entergy only for generation at a fixed rate; accordingly, as a result of the sale, the Company no longer bears the operating costs and risks associated with running the plant or the costs and risks associated with the eventual decommissioning of the plant.

NOTE 5 - RETAIL RATES

     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.

Vermont Retail Rate Proceedings

     The Company's June 26, 2001 rate order 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 Vermont Department of Public Service ("DPS") reached a rate case settlement that would end uncertainty over the future recovery of Hydro-Quebec contract costs, allow a 3.95 percent rate increase, make the January 1, 1999 temporary rates permanent, permit a return on equity of 11 percent for the twelve 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 percent 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 percent rate increase versus the 7.6 percent 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 principle 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 the 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 Vermont Joint Owners ("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; the Company's share was approximately $4.3 million. In the third quarter of

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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 summarizing its agreement with the DPS on application of the remaining $1.6 million of the Hydro-Quebec settlement to remaining regulatory assets. On September 10, 2002 and in response to a PSB request, the Company filed its amended proposal as agreed to with the DPS.

     On October 4, 2002, the PSB issued an Order approving the Company's proposal for reducing certain regulatory assets by approximately $2.0 million through application of the remaining Hydro-Quebec settlement and the ongoing Millstone Unit #3 decommissioning non-payments. Although the Company is recovering the Millstone Unit #3 decommissioning costs in rates, its payments for decommissioning have ceased. In the third quarter of 2002, based on the PSB Order, the Company reduced certain of its regulatory assets related to Conservation and Load Management by approximately $2.0 million. The Company will account for the ongoing Millstone Unit #3 decommissioning non-payments as a regulatory liability, with carrying charges, to be addressed in the Company's next rate proceeding. Also see Note 2, Regulatory Accounting.

New Hampshire Retail Rate/Federal Court Proceedings

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

     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.

     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

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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:

"the district court may defer vacation of this injunction against the refund order for up to 90 days. If within that period it has decided the merits of the request for a permanent injunction in a way inconsistent with refunds, or has taken any other action that provides a showing that the Company is likely to prevail on the merits in federal court in barring the refunds, it may enter a superseding injunction against the refund order, which the Commission may then appeal to us. Otherwise, no later than the end of the 90-day period, the district court must vacate its present injunction insofar as it enjoins the Commission's refund order."

     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.

     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 percent 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. In September 2001, 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.

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     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 percent such that a zero rate change would occur at January 1, 2002 and the 9.3 percent 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 percent 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 percent 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 October 1, 2002, Connecticut Valley implemented New Hampshire's statewide low-income energy assistance program referred to as the Tiered Discount Program ("TDP"). Under this NHPUC approved program, New Hampshire electric utilities collect a system benefits charge, apply discounted rates to participant bills, forgive any past due balances to August 31, 2002, deduct any authorized start-up and administrative costs, and remit the balance to the State. A statewide system benefits charge fund makes up the shortfall if the system benefits charge does not wholly reimburse a particular utility. The NHPUC also approved a $0.0012 per kWh surcharge for Connecticut Valley (which is not subject to the system benefits charge) to fund the TDP.

FERC Proceedings

     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

Page 12 of 43

totaling approximately $32.9 million as of December 31, 2003. The Company would also be required to write-off approximately $0.7 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, and therefore the Company would be required to recognize the loss discussed above.

     In addition to its efforts before the Court and FERC, Connecticut Valley continues to work for a negotiated settlement with parties to the New Hampshire restructuring proceeding and the NHPUC. On October 29, 2002, the Company, jointly with the NHPUC, requested that the FERC postpone issuance of its final exit fee order while the parties continue to negotiate.

     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.

Wheelabrator Power Contract

     Connecticut Valley purchases power from several Independent Power Producers, who own qualifying facilities as defined by the Public Utility Regulatory Policies Act of 1978. For the nine months ended September 30, 2002, under long-term contracts with these qualifying facilities, Connecticut Valley purchased 29,638 mWh, of which 93 percent 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 that 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.

     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. 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. 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. The NHPUC has selected an independent mediator and the parties had the first meeting with the mediator in late October 2002. The Company cannot predict the timing or final outcome of this matter.

NOTE 6 - ENVIRONMENTAL

     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

Page 13 of 43

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 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. 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 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. 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 was approved. The corrective action plan is now in place, including periodic groundwater monitoring and institutional 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 was 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

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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.

     As of September 30, 2002, a reserve of $7.5 million is recorded on the Condensed 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.

NOTE 7 - REDEEMABLE PREFERRED STOCK

     The 8.3 percent 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. In the third quarter of 2002, the Company repurchased $3.0 million of its 8.3 percent series preferred stock from one of the Company's preferred shareholders.

NOTE 8 - RECONCILIATION OF NET INCOME AND COMMON STOCK OUTSTANDING

     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):

	Three Months Ended September 30		Nine Months Ended September 30
	2002	2001	2002	2001
Net income	$5,855	$3,565	$14,615	$7,789
Preferred stock dividend requirements	380	424	1,187	1,272
Net income available for common stock	$5,475	$3,141	$13,428	$6,517
Average shares of common stock outstanding - basic	11,697,336	11,554,588	11,660,792	11,544,227
Dilutive effect of stock options	99,570	-	106,848	100,563
Dilutive effective of performance plan shares	141,788	-	141,788	141,986
Average shares of common stock outstanding - diluted	11,938,694	11,554,588	11,909,428	11,786,776

NOTE 9 - SEGMENT REPORTING

     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 engages in the sale or rental of electric water heaters through a subsidiary, SmartEnergy Water Heating Services, Inc., to customers in Vermont and New Hampshire. As of September 30, 2002, Eversant had an 11.9 percent ownership interest, on a fully diluted basis, in the Home Services Store ("HSS"), which operates a nationwide home improvement business.  In the first quarter of 2002, the Company decided to discontinue Eversant's efforts to pursue n on-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.

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

     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 nine months ended September 30, 2002 and 2001 is as follows (dollars in thousands):

THREE MONTHS ENDED SEPTEMBER 30
	CV VT	CVEC NH	Catamount	Eversant	Other (1)	Reclassification and Consolidating Entries	Consolidated
2002
Revenues from external customers	$  70,210	$  5,526	$     116	$    498	$     -	$    617	$  75,733
Intersegment revenues	3,237	-	-	-	-	3,237	-
Equity income - utility affiliates	2,228	-	-	-	-	-	2,228
Equity income - non-utility affiliates	-	-	2,723	-	-	2,723	-
Net income (loss)	7,514	80	(1,689)	(53)	3	-	5,855
Total assets	446,562	13,230	57,789	3,028	331	3,226	517,714
2001
Revenues from external customers	$  70,137	$  5,001	$     53	$    451	$     -	$    507	$  75,135
Intersegment revenues	2,559	-	-	-	-	2,559	-
Equity income - utility affiliates	699	-	-	-	-	-	699
Equity income - non-utility affiliates	-	-	1,171	-	-	1,171	-
Net income (loss)	4,533	301	34	(1,304)	1	-	3,565
Total assets at December 31, 2001	449,820	12,191	58,266	4,531	321	3,455	521,674
NINE MONTHS ENDED SEPTEMBER 30
2002
Revenues from external customers	$208,717	$  15,403	$     416	$    1,421	$     -	$1,846	$224,111
Intersegment revenues	8,718	-	-	-	-	8,718	-
Equity income - utility affiliates	3,555	-	-	-	-	-	3,555
Equity income - non-utility affiliates	-	-	8,233	-	-	8,233	-
Net income (loss)	15,578	249	(778)	(440)	6	-	14,615
Total assets	446,562	13,230	57,789	3,028	331	3,226	517,714
2001
Revenues from external customers	$211,272	$15,782	$     184	$   1,493	$     -	$1,682	$227,049
Intersegment revenues	8,490	-	-	-	-	8,490	-
Equity income - utility affiliates	2,057	-	-	-	-	-	2,057
Equity income - non-utility affiliates	-	-	3,900	-	-	3,900	-
Net income (loss)	8,334	421	560	(1,533)	7	-	7,789
Total assets at December 31, 2001	449,820	12,191	58,266	4,531	321	3,455	521,674

(1)     Includes a segment below the quantitative threshold.

NOTE 10 - RECENT ACCOUNTING PRONOUNCEMENTS

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 that the change in the contract's fair value be deferred on the balance sheet as either a deferred asset or liability. At September 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 Condensed Consolidated Balance Sheet along with an offsetting deferred asset, which is included in Other deferred charges.

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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 recognition of goodwill as an asset in a business combination but does not permit amortization as was done in the past. 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 in the past. 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. The Company has no goodwill, there fore the adoption of SFAS No. 142 has no material financial statement impact.

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 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.

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 ("SFAS No. 121"). 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). SFA S No. 144 became effective on January 1, 2002. 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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CENTRAL VERMONT PUBLIC SERVICE CORPORATION

Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

     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. Also, refer to the Company's Internet website address: http://www.cvps.com for additional information and the Internet website address for the Company's filings with the U. S. Securities and Exchange Commission: http://www.sec.gov.

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 Vermont and New Hampshire regulatory policies, the outcome of litigation at the Federal Energy Regulatory Commission ("FERC") involving the Company's regulated companies, the status of wholesale power markets in the Northeast, the performance of the Vermont Yankee nuclear power plant ("Vermont Yankee"), weather conditions, the performance of the Company's non- regulated businesses and the state of the economy in the areas served. The Company cannot predict the outcome of any of these matters.

CRITICAL ACCOUNTING POLICIES

     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. A summary of the significant accounting policies used in the preparation of the Company's financial statements is included in Note 1 to the Consolidated Financial Statements in the Company's 2001 Annual Report on Form 10-K. The following is a discussion of critical accounting policies used by the Company.

Regulation The Company is subject to regulation by the Vermont Public Service Board ("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 c riteria 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 $33.1 million on a pre-tax basis as of September 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 and September 30, 2002. 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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Revenue The Company follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the monthly accounting period. The determination of unbilled revenues requires the Company to make various estimates including:

• Energy generated, purchased and resold
• Losses of energy over transmission and distribution lines
• Kilowatt-hour usage by customer mix (residential, commercial and industrial)

Pension and Other Postretirement Benefits The Company records pension and other postretirement benefit costs in accordance with SFAS No. 87, Employers' Accounting for Pensions, and SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions. Under these accounting standards, assumptions are made regarding the valuation of benefit obligations and performance of plan assets. Delayed recognition of differences between actual results and those assumed is a guiding principle of these standards. This approach allows for a smoothed recognition of changes in benefit obligations and plan performance over the working lives of the employees who benefit under the plans. The following is a list of the primary assumptions, which are reviewed annually for the September 30 measurement date.

• Discount Rate - The discount rate is used to record the value of benefits, which are based on future projections, in terms of today's dollars.

• Expected Return on Plan Assets - The Company projects the future return on plan assets based principally on prior performance and receives guidance from the Company's actuaries. The projected future value of assets reduces the benefit obligation a company will record.

• Rate of Compensation Increase - The Company projects employees' annual pay increases, which are used to project employees pension benefits at retirement.

• Health Care Cost Trend - The Company projects the expected increases in the cost of health care.

• Amortization of Gains/(Losses) - The Company can select the method by which gains or losses are recognized in financial results. These gains or losses are created when actual results differ from estimated results based on the above assumptions.

     A variance in the discount rate, expected return on plan assets, rate of compensation increase or amortization method could have a significant impact on the pension costs recorded under SFAS No. 87. A variance in the health care cost trend assumption could have a significant impact on costs recorded under SFAS No. 106 for postretirement medical expense. The impact of a one-percentage point variance in the assumed health care cost trend is calculated by the Company's actuaries. The market value of pension plan assets has been affected by sharp declines in the equity market. As a result, the Company anticipates an increase in pension expense for 2003; pension cost and cash funding requirements could increase in future years without a substantial recovery in the equity markets. For further information, refer to the consolidated financial statements and footnotes thereto included in the Company's Annual Report on Form 10-K.

RESULTS OF OPERATIONS

Earnings Overview

     The Company recorded net income of $5.9 million, or $.47 per basic and $.46 per diluted share of common stock, for the third quarter of 2002 compared to net income of $3.6 million, or $.27 per basic and diluted share of common stock, for the third quarter of 2001. Higher third quarter 2002 earnings compared to the same period in 2001 resulted from the following factors:

• higher retail sales revenue and other operating revenue of $1.8 million after-tax, or $.15 per share of common stock, primarily resulting from a 2.2 percent increase in retail mWh sales and the sale of non-firm transmission under the Company's open access transmission tariff;

• higher net power costs of $1.0 million after-tax, or $.09 per share of common stock, mainly due to higher retail sales and higher capacity requirements;

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• favorable impact of $2.5 million after-tax, or $.22 per share of common stock, resulting from the Vermont Yankee sale, primarily due to state tax benefits now available to Vermont Yankee, which were passed on to the owners; although the sale closed on July 31, 2002, the Company's distribution from the sale proceeds and final accounting for the sale are pending certain regulatory approvals and the resolution of certain closing items between the seller and purchaser;

• higher operating and other costs of $0.7 million after-tax, or $.06 per share of common stock, primarily due to a $0.6 million, or $.05 per share of common stock, one-time payment related to closing the Vermont Yankee sale, higher property tax expense of $0.2 million, or $.02 per share of common stock, and lower interest and dividend income of $0.1 million, or $.01 per share of common stock, offset by lower administrative and general expenses of $0.2 million, or $.02 per share of common stock;

• net losses at Catamount Energy Corporation of $1.7 million, or $.15 per share of common stock, compared to nominal earnings in 2001, primarily resulting from third quarter 2002 after-tax asset impairment charges of $2.1 million, or $.18 per share of common stock, related to the pending sale of certain of its equity investments, primarily offset by higher equity earnings from one of its investments;

• lower losses at Eversant Corporation of $1.3 million, or $.11 per share of common stock, primarily related to a third quarter 2001 write-down of its investment in Home Service Store, Inc; and

• a third quarter 2001 extraordinary charge of $0.2 million, or $.02 per share of common stock, resulting from the Company's New Hampshire subsidiary, Connecticut Valley, again being subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.

     For the nine months ended September 30, 2002, the Company had net income of $14.6 million, or $1.15 per basic and $1.13 per diluted share of common stock, compared to net income of $7.8 million, or $.56 per basic and $.55 per diluted share of common stock, for the nine months ended September 30, 2001. Higher nine months ended September 30, 2002 earnings compared to the same period last year resulted from the following factors:

• higher retail sales revenue and other operating revenue of $3.7 million after-tax, or $.32 per share of common stock, resulting from higher average retail rates due to the June 26, 2001 rate order, which allowed for a 3.95 percent increase in retail rates beginning July 1, 2001, a small increase in retail mWh sales and the sale of non-firm transmission under the Company's open access transmission tariff;

• higher net power costs of $2.7 million after-tax, or $.23 per share of common stock, 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 lower ISO-New England market prices for resale sales, offset by installed capacity deficiency credits;

• favorable impact of $2.5 million after-tax, or $.22 per share of common stock, resulting from the Vermont Yankee sale, primarily due to state tax benefits now available to Vermont Yankee, which were passed on to the owners; although the sale closed on July 31, 2002, the Company's distribution from the sale proceeds and final accounting for the sale are pending certain regulatory approvals and the resolution of certain closing items between the seller and purchaser;

• higher operating and other costs of $0.2 million, or $.02 per share of common stock, primarily related to the following after-tax items: 1) a $0.6 million, or $.05 per share of common stock, one-time payment related to closing the Vermont Yankee sale, 2) higher transmission costs of $0.6 million, or $.05 per share of common stock, 3) higher property tax expense of $0.6 million, or $.05 per share of common stock, 4) an increase in bad debt reserves due to several announced bankruptcies of $0.4 million, or $.04 per share of common stock, 5) a $1.0 million, or $.09 per share of common stock, reversal of certain environmental reserves, 6) lower storm restoration costs of $0.5 million, or $.04 per share of common stock, and 7) lower other operating expenses of $.04 million, or $.04 per share of common stock;

• net losses at Catamount Energy Corporation of $0.8 million, or $.07 per share of common stock, compared to earnings of $0.5 million, or $.05 per share of common stock, in 2001, mainly due to third quarter 2002 after-tax asset impairment charges of $2.1 million, or $.18 per share of common stock, related to the pending sale of certain of its equity investments and higher project development costs, offset by higher equity earnings from one of its investments and lower equity losses on certain other equity investments;

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• lower losses at Eversant Corporation of $1.1 million, or $.09 per share of common stock, primarily related to a third quarter 2001 write-down of its investment in Home Service Store, Inc., the 2002 settlement of an IRS audit resulting in a reversal of an IRS interest expense accrual previously recorded in the fourth quarter of 2001, offset by costs related to the Company's decision to discontinue Eversant's efforts to pursue non-regulated business opportunities;

• a third quarter 2001 extraordinary charge of $0.2 million, or $.02 per share of common stock, resulting from the Company's New Hampshire subsidiary, Connecticut Valley, again being subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation; 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.

Operating Revenues and mWh Sales

Revenues from operations and megawatthour (mWh) sales for the three and nine months ended September 30, 2002 and 2001 are summarized below:

	Three Months Ended September 30				Nine Months Ended September 30
	mWh Sales		Revenues (000's)		mWh Sales		Revenues (000's
	2002	2001	2002	2001	2002	2001	2002	2001
Residential	236,250	224,451	$32,191	$30,473	719,553	713,669	$96,085	$92,947
Commercial	247,924	242,939	29,976	29,020	697,430	695,753	83,716	81,580
Industrial	99,255	103,579	8,228	8,555	315,294	319,282	26,389	26,254
Other retail	1,584	1,621	456	462	4,704	4,749	1,353	1,342
Total retail sales	585,013	572,590	$70,851	$68,510	1,736,981	1,733,453	$207,543	$202,123
Resale sales:
Firm	346	282	$29	$30	1,382	1,416	$94	$104
Entitlement	-	53,659	-	1,876	-	146,677	-	6,588
Other	77,962	86,299	2,950	3,455	335,887	325,131	10,979	13,665
Total resale sales	78,308	140,240	2,979	5,361	337,269	473,224	11,073	20,357
Other revenues	-	-	1,903	1,264	-	-	5,495	4,569
Total	663,321	712,830	$75,733	$75,135	2,074,250	2,206,677	$224,111	$227,049

     Retail sales revenue increased $2.3 million, or 3.4 percent, in the third quarter of 2002 primarily due to a 2.2 percent increase in mWh sales compared to the same period in 2001. For the nine months ended September 30, 2002, retail sales revenue increased $5.4 million, or 2.7 percent, due to the 3.95 percent retail rate increase, which became effective July 1, 2001 and a slight increase in mWh sales compared to the nine months ended September 30, 2001.

     Entitlement sales in the third quarter and nine months of 2001 were related to a five-year power contract in which the Company sold approximately 15 percent 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 in the third quarter of 2002 decreased $0.5 million compared to the third quarter of 2001 due to a 9.7 percent decrease in mWh sales and lower average ISO-New England market prices at the time of the sales. For the nine months ended September 30, 2002, Other resale sales decreased $2.7 million primarily due to lower average ISO-New England market prices. Related mWh sales for the same period increased 3.3 percent due to the end of the Vermont Yankee entitlement sale and an 11.8 percent 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.

     Other revenues in the third quarter and nine months of 2002 are $0.6 million and $0.9 million higher than the comparable periods in 2001 primarily due to the sale of non-firm transmission under the Company's open access transmission tariff.

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Net Purchased Power and Production Fuel Costs

The cost components of net purchased power and production fuel for the three and nine months ended September 30, 2002 and 2001 are as follows (dollars in thousands):

	Three Months Ended September 30				Nine Months Ended September 30
	2002		2001		2002		2001
	mWh	Amount	mWh	Amount	mWh	Amount	mWh	Amount
Capacity		$14,062		$21,365		$60,198		$62,881
Energy	651,314	19,211	687,926	14,705	1,952,296	46,952	2,116,610	47,563
Total purchased power		33,273		36,070		107,150		110,444
Production fuel   Total purchased and production	70,053	956 34,229	71,923	913 36,983	282,199	1,951 109,102	245,682	2,388 112,832
Less resale sales excl firm	77,962	2,950	139,958	5,331	335,887	10,979	471,808	20,253
Net purchased power and    production fuel costs	643,405	$31,279	619,891	$31,652	1,898,608	$98,123	1,890,484	$92,579

     The Company's power cost structure undertook a major change beginning in July 2002 due to the sale of its share of Vermont Yankee to Entergy and the agreement to purchase a similar share of the output on a per-mWh basis, all recorded as energy purchases. Prior to the sale, the great majority of Vermont Yankee costs were recorded as capacity costs. As a result of the sale transaction, the Company's third quarter 2002 purchased power costs decreased significantly compared to the third quarter of 2001. Net purchased power and production fuel costs decreased $0.4 million in the third quarter of 2002 despite a 23,514 mWh increase in net energy purchases, while nine months ended September 30, 2002 net power costs increased $5.5 million with a 8,124 mWh increase in net energy purchases. A more detailed explanation of net purchased power costs follows.

     Capacity costs decreased $7.3 million in the third quarter of 2002 compared to the same period in 2001 mostly related to the July 31, 2002 sale of Vermont Yankee. Favorable impacts included $2.2 million related to state tax benefits now available to Vermont Yankee, which were passed on to the owners, and approximately $6.0 million related to lower capacity costs because the Company is no longer responsible for Vermont Yankee capacity costs.

     For the nine months of 2002, capacity costs decreased $2.7 million compared to the same period in 2001 primarily due to the favorable impacts of the Vermont Yankee sale described above, offset by second quarter 2001 nonrecurring items. The 2001 nonrecurring items included 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 costs for installed capacity in ISO-New England due to the resolution of a December 2000 FERC Order. Other factors affecting capacity costs for nine months of 2002 compared to the same period in 2001 include installed capacity deficiency credits received by the Company from ISO-New England.

     In May 2002, Vermont Yankee had an unscheduled 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 Condensed Consolidated Balance Sheet. For additional information regarding the Accounting Order see Nuclear Matters, Vermont Yankee - Operations below.

     Energy purchases increased $4.5 million for the third quarter of 2002 compared to the third quarter of 2001 due to the change in Vermont Yankee cost structure described above and the Company's increased entitlement in Vermont Yankee as explained in Operating revenues above. Energy purchases decreased $0.6 million for the nine months ended September 30, 2002 compared to the same period 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 and the change in Vermont Yankee cost structure combined with the higher Vermont Yankee entitlement.

     Third quarter and nine months-ended resale sales are explained in Operating revenues above.

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     Production fuel costs decreased $0.4 million for the nine months ended September 30, 2002 compared to the same period 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.

Other Operating Costs

Other major elements of the Condensed Consolidated Statement of Income are discussed below.

Production and transmission  The increase of $1.0 million in the nine months of 2002 compared to 2001 resulted mostly from higher ISO-New England transmission congestion charges.

Other operation expenses The increase of approximately $1.3 million for the third quarter resulted from decreased conservation and load management deferrals due to the Company's 2001 rate case settlement in which the Company agreed to discontinue certain deferrals by July 2002 and higher overhead line expense. The decrease of $1.1 million for the nine months of 2002 versus 2001, resulted primarily from a reduction of environmental reserves, related to the Dover, New Hampshire site, lower storm restoration costs, partially offset by an increase in bad debt reserves due to certain bankruptcies.

Maintenance expenses  The $1.3 million decrease in maintenance expense in the nine months 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 $0.3 million in the third quarter and $0.9 million in the nine months 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 increased in the third quarter and nine months of 2002 compared to 2001, due to changes in permanent differences for the periods.

Other income and deductions  Other income and deductions decreased $0.5 million for the third quarter of 2002, compared to 2001, mostly due to net losses at Catamount, primarily resulting from third quarter 2002 asset impairment charges of $2.7 million, related to the pending sale of certain of its equity investments and higher project development costs, offset by higher equity earnings from one of its investments, lower interest and dividend income and a one-time payment in the amount of approximately $1.0 million related to closing the Vermont Yankee sale, offset by lower losses at Eversant Corporation, primarily related to a third quarter 2001 write-down of approximately $2.0 million, related to its investment in The Home Service Store, Inc.

     Other income and deductions increased $7.3 million in the nine months of 2002, compared to 2001, mostly due to 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. Other contributing factors are described above for the third quarter.

Other interest expense  The $0.3 million decrease in Other interest expense in the nine months of 2002, compared to 2001, was due to the reversal of Eversant's IRS interest expense accrual, due to the settlement of an IRS audit in 2002.

Extraordinary charge net of taxes The third quarter 2001 Extraordinary charge of $0.2 million, resulted from the Company's New Hampshire subsidiary, Connecticut Valley, again being subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.

Common stock The $2.5 million decrease in Common stock dividends in the third quarter and nine months of 2002, compared to the same periods in 2001, is due to timing.

Other adjustments  The $0.1 million increase in Other adjustments in the third quarter and nine months of 2002, compared to the same periods in 2001, resulted primarily from an adjustment to retained earnings related to stock option exercises.

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POWER SUPPLY

Nuclear Matters

     The Company maintains a 1.7303 percent joint-ownership interest in Unit #3 of the Millstone Nuclear Power Station and owns a 2, 2 and 3.5 percent equity interest in Connecticut Yankee, Maine Yankee and Yankee Atomic, respectively. On July 31, 2002, the Vermont Yankee plant was sold to Entergy, however the Company has a 33.23 percent 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 percent. See below for more detail related to Vermont Yankee.

     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. In August 2001, the Financial Accounting Standards Board issued SFAS No. 143, Accounting for Asset Retirement Obligations, or SFAS No. 143, which provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of long-lived assets, including nuclear decommissioning obligations. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. 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.

Vermont Yankee 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 ("PPA") 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. Certain residual Vermont Yankee costs will continue to be billed by Vermont Yankee to its sponsors in addition to the PPA costs from Entergy. 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 Comp any 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 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 percent to 33.23 percent.

     Following hearings in February 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 recommended 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 ("NRC") 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

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• 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. Under the terms of the agreements, Vermont ratepayers will receive 100 percent of the Vermont utilities' share of any surplus remaining in the decommissioning fund when the plant is decommissioned. The non-Vermont owners, representing 45 percent ownership of the plant, will restore the substance of the original agreement by assigning 100 percent of their excess decommissioning funds to Entergy. The Company agreed to contribute approximately $1.0 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.

     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 also 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 has a 33.23 percent equity interest in Vermont Yankee Nuclear Power Corporation ("VYNPC"), which will continue as a Vermont-based corporation and will administer the purchase power contracts among the former plant owners and Entergy. Certain residual VYNPC costs will continue to be billed by VYNPC to its sponsors in addition to purchased power costs from Entergy. The Company also receives its 35 percent entitlement of Vermont Yankee output sold by Entergy to VYNPC under the PPA described above. Additionally, two remaining secondary purchasers will continue receiving a small percentage of the Company's entitlement.

     Although the sale closed on July 31, 2002, the Company's distribution from the sale proceeds and final accounting for the sale are pending certain regulatory approvals and the resolution of certain closing items between the seller and purchaser. The Company expects its share of the Vermont Yankee sale proceeds to be distributed in 2003. Third quarter 2002, accounting related to the Vermont Yankee sale includes the following:

• The Company recorded a $0.6 million after-tax one-time expense related to a shareholder payment for the Company's contribution to the non-Vermont owners of the plant as described above. This one-time expense is included in Other Income and Deductions on the Company's Condensed Consolidated Statement of Income.

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• The Company deferred approximately $3.2 million after-tax in the third quarter of 2002, based on an approved Accounting Order from the PSB. The Accounting Order authorizes the Company to defer the incremental costs that occur in 2002 in connection with the sale and increased purchased power costs under the PPA contracts compared to costs if the Company had continued to own the plant. The purchased power contract between Entergy and Vermont Yankee is forecasted to lead to higher purchased power costs in the initial years of the contract with decreased costs in future years when compared to continued ownership of the plant. Also see Note 2 to the Condensed Consolidated Financial Statements.

• The Company recorded a $1.3 million after-tax reduction in purchased power expense and a $1.2 million after-tax increase in equity earnings from Vermont Yankee. The $2.5 million after-tax favorable impact was primarily due to state tax benefits now available to Vermont Yankee, which were passed on to the owners. The favorable impact is included in the Company's Condensed Consolidated Statement of Income.

     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.

Vermont Yankee - Operations: 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 May 2002 Vermont Yankee mid-cycle outage.

     Vermont Yankee accomplished a 21-day refueling outage between October 5 and October 27, 2002. Although the Company is no longer responsible for refueling outage costs, it remains responsible for procuring replacement energy during the outage and any other Vermont Yankee outages in the future. As such, the Company no longer defers or amortizes incremental capacity and replacement energy costs as it had done in the past. Under the PPA, the Company pays Entergy only for generation at a fixed rate; accordingly, as a result of the sale, the Company no longer bears the operating costs and risks associated with running the plant or the costs and risks associated with the eventual decommissioning of the plant.

Millstone Unit #3 The Company is one of two minority owners of Millstone Unit #3, however, the total Dominion Nuclear Connecticut ("DNC") share is 93.4707 percent. On March 31, 2001, DNC, a subsidiary of Dominion Resources, Inc., purchased Millstone Unit #3 from Northeast Utilities. As part of the regulatory approvals for the sale, DNC represented to the NRC and other regulatory bodies that its share of the Millstone Unit #3 Decommissioning Trust Fund exceeds the NRC minimum calculation required and therefore no further contributions to the fund are required at this time. In its recent rate case, the Company agreed with the DPS that DNC's representation that contributions currently can cease is appropriate subject to periodic review of both the fund balance and the NRC minimum calculation upon which DNC based 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.

Maine Yankee 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 percent 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 the 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 Yankee 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.

Connecticut Yankee 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 percent 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

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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.

Yankee Atomic In 1992, the Yankee Atomic nuclear power plant was retired from commercial operation. The Company relied on Yankee Atomic for less than 1.5 percent 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.

Nuclear Decommissioning Costs Currently, the Company's share of Maine Yankee and Connecticut Yankee costs, including a provision for ultimate decommissioning of the units, are being collected from the Company's customers through existing retail and wholesale rate tariffs. The Company's share of remaining costs with respect to Maine Yankee and Connecticut Yankee's decisions to discontinue operation were estimated to be $9.1 million and $3.9 million, respectively, at September 30, 2002. As of December 31, 2000, the Company completed its obligation for decommissioning costs based on current estimates related to Yankee Atomic. These amounts are subject to ongoing review and revisions and are reflected in the accompanying Condensed Consolidated Balance Sheet both as regulatory assets and nuclear decommissioning 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.

Cogeneration/Independent Power Qualifying Facilities

     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-appointed purchasing agent who purchases and redistributes the power to all Vermont utilities pursuant to PSB Rule 4.100. For the nine months ended September 30, 2002, the Company received 152,839 mWh under these long-term contracts, representing 7.8 percent of total mWh purchases and 32.3 percent of the Company's total purchased power expense for the period. The total mWh received under these contracts includes 112,157 mWh allocated by the Purchasing Agent, VEPP Inc., and 27,670 mWh purchased by Connecticut Valley, the Company's wholly owned New Hampshire subsidiary, from a waste-to-energy electric generating facility owned by Wheelabrator Cl aremont 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 finding that it has jurisdiction to consider certain of the requests for 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.

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     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 2000 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 10 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 by 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 buy-downs 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 possible by the end of 2002.

Generating Units

     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 six separate hydroelectric projects under the Federal Power Act. These projects, some of which are grouped together under a single license, represent approximately 24.5 mW, or about 54.8 percent 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.

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LIQUIDITY AND CAPITAL RESOURCES

     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 $80.0 to $85.0 million; these projections are revised from time-to-time to reflect changes in conditions. Net cash flow provided by operating activities generated $28.6 million and $22.8 million of cash for the nine months ended September 30, 2002 and 2001, respectively.

     The Company ended the nine months of 2002 with cash and cash equivalents of $50.0 million, an increase of $4.5 million from the beginning of the year. The increase in cash for 2002 was the result of $28.6 million provided by operating activities, offset by $10.1 million used for investing activities and $14.0 million used for financing activities.

     Operating Activities Net income and depreciation, deferred income taxes and investment tax credits provided cash of $29.0 million. Approximately $0.4 million of cash was used by working capital and other operating activities.

     Investing Activities Construction and plant expenditures used cash of approximately $9.4 million, the Company's investment in Velco used $0.5 million and $0.2 million was used for non-utility investments.

     Financing Activities Dividends paid on common stock were $7.7 million, while preferred stock dividends were $1.6 million. The redemption of preferred stock required $4.0 million and the pay down of capital lease obligations required $0.8 million. Net long-term debt used $1.2 million, the sale of common stock from the Company's Treasury shares provided $0.4 million and proceeds from the Company's dividend reinvestment program provided $0.9 million.

Utility

     The 8.3 percent 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 also repurchased $3.0 million of its 8.3 percent series preferred stock from one of the Company's preferred shareholders, 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 was effective on August 22, 2002. The Company had in place a supplemental indenture allowing the letter of credit to transfer. These letters of credit are secured by a first mortgage lien on the same collateral supporting the Company's first mortgage bonds.

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

Non-Utility

     In 1998, Catamount replaced its $8.0 million credit facility with a $25.0 million revolving credit/term loan facility, which provides for up to $25.0 million in revolving credit loans and letters of credit, of which $21.3 million was outstanding at September 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 September 30, 2002, including Catamount's office building mortgage, the aggregate amount of Catamount's long-term debt maturities are $0.0 million, $9.2 million, $6.3 million, $3.7 million and $2.3 million for the years 2002 through 2006, respectively. In October 2002, Catamount sold its investments in Heartlands Power Limited ("Heartlands") and the net proceeds from the sale of approximately $5.0 million will be used to pay down the outstanding revolver. Catamount's long-term debt contains financial and non-financial covenants. At March 31, 2002, Catamount was in compl iance 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 noncompliance 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 September 30, 2002, Catamount was in compliance with all covenants under the revolver except that Catamount's capital expenditures exceeded the annual budget by an immaterial amount, which was waived by the lender on October 31, 2002. Catamount's ability to borrow under the facility expired November 12, 2002, however, Catamount issued a proposal

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to their lender to extend the credit facility. The proposal calls for a two-year extension of the revolver which would allow Catamount to borrow against new operating projects subject to the terms and conditions of the facility and a revised term-out schedule for the existing outstanding loans from the one indicated above. Catamount received a letter from the lender dated November 12, 2002, indicating that the lender is in the process of seeking credit approval of the proposal and would begin amortizing the existing outstanding loans according to Catamount's proposed term-out schedule, however, there is no guarantee the facility will be extended and that Catamount would be able to find a replacement corporate credit facility. Catamount's proposed term-out schedule calls for the outstanding debt to be paid down to $15.0 million by March 31, 2003, $11.0 million by November 12, 2003 and to $0.0 by November 12, 2004. See Diversification below for additional information related to Catamount.

     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 and paid in full the outstanding balance of $1.0 million in the third quarter of 2002.

Credit Ratings

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

	Standard & Poor's (1)	Fitch (2)
Corporate Credit Rating	BBB-	N/A
First Mortgage Bonds	BBB+	BBB
Second Mortgage Bonds	BBB-	BBB-
Preferred Stock	BB	BB+

1. Outlook: Stable
2. Outlook: Stable

     On October 21, 2002, Standard & Poor's affirmed the Company's BBB- Corporate Credit Rating and the ratings of the Company's debt and preferred stock. Standard & Poor's said, "The rating affirmation reflects the improvement in the business profile, subsequent to the sale of the company's interest in the Vermont Yankee nuclear plant."

     Vermont Yankee Sale: The sale of Vermont Yankee's assets to Entergy was completed on July 31, 2002, however, the Company's distribution of the sale proceeds and final accounting for the sale are pending certain regulatory approvals and the resolution of certain closing items between the seller and purchaser. The Company expects its share of the Vermont Yankee sale proceeds to be distributed in 2003. Also see Note 4 to the Condensed Consolidated Financial Statements for additional information.

     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.

DIVERSIFICATION

Catamount

     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. As of September 30, 2002, 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

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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-recourse 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 percent owned by Catamount Heartlands Corp., a wholly owned subsidiary of Catamount. The company was formed to hold Catamount's interests in German "greenfield" development projects or projects that would be purchased by Catamount in early- to mid-stage development. In February 2002, Catamount entered into a joint venture agreement with North American Renewables Corp. ("NAR"), 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.

     In February 2002, Catamount entered into a joint development agreement with force9energy Ltd. Of England to develop wind projects in England, Scotland and Wales. In September 2002, Catamount established Catamount Energy, Ltd., an English corporation, to hold Catamount's interest in England, Scotland and Wales "greenfield" development projects or projects that would be purchased by Catamount in early to mid-stage development.

     Catamount's after-tax losses were $1.7 million and $0.0 million for the third quarter of 2002 and 2001, respectively, and after-tax losses of $0.8 million, compared to earnings of $0.6 million for the nine months of 2002 and 2001, respectively. Additional information regarding certain of Catamount's investments follows.

     Gauley River At December 31, 2001, the Company made the decision to actively market for sale its project interest in Gauley River and therefore classified its interests as current non-utility investments. In the fourth quarter of 2001, 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.

     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.

     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. In the third quarter 2002, Catamount recorded an additional $0.8 million after-tax impairment charge to earnings based on funding certain escrow accounts as a condition of the Purchase and Sale Agreement. The FERC has approved the sale and the Federal Trade Commission has approved the Hart-Scott-Rodino filing. The sale is pending 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.

     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 percent ownership. The Gauley River project had total assets of $55.9 million and total liabilities of $46.9 million at September 30, 2002.

     Fibrothetford Limited ("Fibrothetford") Catamount's equity investment in Fibrothetford 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 $1.5 million through December 31, 2002.

     At December 31, 2001, Catamount's Fibrothetford investment was classified as a current non-utility investment since Catamount was actively marketing its interests in Fibrothetford. 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 related to Fibrothetford 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.

     In September 2002, Catamount entered into a Memorandum of Understanding with a third party for the sale of its Fibrothetford investment interests. Catamount expects the sale to be finalized in the fourth quarter 2002 and expects the proceeds from the sale to exceed the net book value of its investments in Fibrothetford.

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     Glenns Ferry and Rupert 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 and 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 and therefore classified its interests as current non-utility investments.

     Heartlands In the third quarter of 2002, Catamount recorded an after-tax impairment charge to earnings of $1.3 million related to the pending sale of its equity investment in Heartlands and also classified its interests in Heartlands as current non-utility investments. On October 30, 2002, Catamount sold its 50 percent interest in Heartlands to a third party, resulting in a nominal loss. The net proceeds from the sale of approximately $5.0 million will be used to pay down Catamount's outstanding revolver.

Eversant

     Eversant, also a subsidiary of Catamount Resources Corporation, had an 11.9 percent ownership interest, on a fully diluted basis, in HSS, as of September 30, 2002. HSS has established a network of affiliate contractors who perform home maintenance repair and improvements for HSS members. HSS began operations in 1999 and is subject to risks and challenges similar to a company in the early stage of development. In May 2001, Eversant entered into a convertible loan agreement with HSS and Jupiter Partners II L.P. ("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 September 2001, Eversant recorded a $1.2 million after-tax write-down of its investment in HSS to fair value. Eversant had previously recorded losses of $9.0 million related to its investment in HSS. At the end of 2001, Jupiter committed, based upon continued satisfactory operating progress, to provide an additional $5.0 million in funding to the business over time. As of July 15, 2002, Jupiter had invested the entire $5.0 million. In September 2002, Jupiter received additional options to acquire up to an aggregate of $4.0 million in additional preferred securities, of which, as of October 31, 2002, Jupiter has already acquired $1.0 million. Jupiter has invested a total of $5.0 million in HSS, in 2002, and is currently talking to other parties about providing capital.

     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 September 30, 2002, Eversant has a preferred equity investment in HSS of $1.4 million, recorded at estimated fair value. On October 25, 2002, Eversant converted certain HSS accrued liabilities in the amount of $0.3 million into equity, in the form of HSS preferred stock. The Company has no obligation to make further funding to HSS. Eversant's ownership interest in HSS, on a fully diluted basis, increased to 12.2 percent as of October 31, 2002.

     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.

     SmartEnergy Water Heating Services, Inc., a wholly owned subsidiary of Eversant, had after-tax earnings of $0.1 million and $0.1 million for the third quarter of 2002 and 2001, respectively, and after-tax earnings of $0.2 million and $0.3 million for the nine months of 2002 and 2001, respectively.

     In the first quarter of 2002, the Company decided to discontinue Eversant's efforts to pursue non-regulated business opportunities, but will continue its water heating business. Overall, Eversant had consolidated after-tax losses of $0.1 million and $1.3 million for the third quarter of 2002 and 2001, respectively, and after-tax losses of $0.4 million and $1.5 million for nine months of 2002 and 2001, respectively.

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RATES AND REGULATION

     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 Condensed Consolidated Financial Statements for information related to Vermont Retail Rates.

Electric Industry Restructuring

     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, have implemented new mechanisms to bring greater competition, customer choice and market influence to the industry while retaining the public benefits associated with the current regulatory system. 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 an indefinite slowdown of the restructuring process in Vermont.

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 to govern retail competition within the Company's service territory. At this time, the PSB has concluded its investigation into the restructuring of committed power supply arrangements in Docket No. 6140 and the proceeding has been closed. Additionally, in December 2001, the PSB issued an order closing Docket No. 6330. As a result, the Company cannot determine when or if retail competition will be introduced within the Company's Vermont service territory.

New Hampshire

     The Company is continuing to work for a negotiated settlement with parties to the New Hampshire restructuring proceedings and the New Hampshire Public Utilities Commission. Also see Note 5 to the Condensed Consolidated Financial Statements for additional information related to FERC Proceedings.

Transmission and Regional Transmission Organizations (RTO)

     Pursuant to FERC Order No. 888 (issued April 1996) the Company operates its transmission system under an open access, nondiscriminatory transmission tariff.

     On May 13, 1999, the FERC issued a notice of proposed rulemaking that would amend FERC's regulations under the Federal Power Act to facilitate the formation of regional transmission organizations ("RTO"). On December 20, 1999, the FERC issued Order No. 2000, which requires all public utilities that own, operate, or control interstate electric transmission to file a proposal for an RTO by October 15, 2000, or in the alternative, a description of any efforts by the utility to participate in an RTO, the reasons for not participating and any obstacles to participation, and any plans for further work toward such participation. The Company, jointly with GMP, Citizens Utilities and Vermont Electric Power Company, filed its comments on the New England RTO proposal submitted by some of the New England transmission owners and ISO-New England on January 16, 2001.

     On July 12, 2001, the FERC issued an order on the New England RTO proposal, which found that the RTO proposed by the New England market participants would be insufficient in its proposed scope and regional configuration to effectively perform an RTO's required functions and to support competitive power markets. The FERC required that the participants in the proceedings involving the three proposed RTOs in the northeast, participate in mediation on forming a single Northeastern RTO. From July 24, 2001 through September 7, 2001, the Company participated in joint mediation with approximately 400 other Northeast participants to develop an RTO, which meets the requirements of Order No. 2000. The primary tasks of the mediation were focused on 1) defining the Northeastern RTO's operational paradigm, 2) developing an infrastructure and operating rules, and 3) implementing the RTO across the entire region. On July 31,2002, FERC issued a Notice of Proposed Rulemaking ("NOPR") for S tandard Market Design ("SMD"). FERC intends to establish nationally consistent power market rules and offers additional options for RTO formation. Under the NOPR, utilities with power marketing activity

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may be required to transfer their transmission assets or control of the assets to an Independent Transmission Provider ("ITP"). The ITP could be an RTO or a combination of an Independent System Operator ("ISO") and Independent Transmission Companies. Comments on the NOPR are due in mid-November.

     On August 23, 2002, ISO-New England and the New York ISO filed a petition with the FERC proposing to establish a single Northeast Regional Transmission Organization ("NERTO") encompassing the six New England states and New York. If approved and established, NERTO would replace ISO-New England as the entity responsible for reliability of the bulk power system, operation of the region's wholesale markets and provision of transmission throughout the region. On November 7, 2002, the Company filed comments on the NERTO petition requesting that FERC require the NERTO to include all transmission assets in a single tariff with a single postage stamp rate to facilitate commerce and resolve the accumulation of rates referred to as pancaking. The PSB and DPS filed comments requesting FERC to dismiss the NERTO petition because it is incomplete, premature and does not provide net benefits to New England.

     On September 20, 2002, the FERC accepted in part ISO-New England's request to implement an SMD governing wholesale energy sales in New England. ISO-New England plans to implement SMD in early 2003. The SMD is expected to include a system of locational marginal pricing of energy under which prices will be determined by zone and based in part on transmission congestion experienced in each zone. Initially, the State of Vermont is expected to comprise a single zone under the plan.

     At this time, the Company is unsure as to the outcome of these matters or the potential affects on the Company.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Utility Risk Factors

Competition

     If retail competition is implemented in Vermont or New Hampshire, the Company is unable to predict the impact on its revenues, the Company's ability to retain existing customers with respect to their power supply purchases and attract new customers or the margins that will be realized on retail sales of electricity, if any such sales are sought. The Company expects its power distribution and transmission service to its customers to continue on an exclusive basis subject to continuing economic regulation.

     Historically, electric utility rates in Vermont and New Hampshire have been based on a utility's costs. As a result, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. SFAS No. 71 requires regulated entities, in appropriate circumstances, to establish regulatory assets and liabilities, and thereby defer the income statement impact of certain costs and revenues that are expected to be realized in future rates.

     As described in Note 1 of Notes to the Consolidated Financial Statements in the Company's 2001 Annual Report on Form 10-K, the Company believes it currently complies with the provisions of SFAS No. 71 for both its regulated Vermont and New Hampshire service territory and FERC-regulated wholesale businesses. In the event the Company determines that it no longer meets the criteria for following SFAS No. 71, the accounting impact would be an extraordinary, non-cash charge to operations of approximately $33.1 million on a pre-tax basis as of September 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.

     On January 1, 2002, the Company adopted SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS No. 144") which replaces SFAS No. 121, which the Company previously adopted on January 1, 1996. As with SFAS No. 121, SFAS No. 144 requires that any assets, including regulatory assets, that are no longer probable of recovery through future revenues, be revalued based upon undiscounted future cash flows. SFAS No. 144 requires that a rate-regulated enterprise recognize an impairment loss for the amount of costs excluded from recovery. As of September 30, 2002, based upon the regulatory environment within which the Company currently operates, SFAS No. 144 did not have an impact on the Company's regulated businesses. Competitive influences or regulatory developments may impact this status in the future.

     Because the Company is unable to predict what form possible future restructuring legislation will take, it cannot predict if or to what extent SFAS No. 71 will continue to be applicable in the future. If the Company is unable to mitigate or otherwise recover stranded costs that could arise from any potentially adverse legislation or regulation, the Company would have to assess the likelihood and magnitude of losses incurred under its power contract obligations. As such, the Company cannot predict whether any restructuring legislation enacted in Vermont or New Hampshire, once implemented, would have a material adverse effect on the Company's operations, financial condition or credit ratings. However, the Company's failure to recover a significant portion of its purchased power costs would likely have a material adverse effect on the Company's results of operations, cash flows, ability to obtain capital at competitive rates and ability to exist as a going concern. It is pos sible that stranded cost exposure before mitigation could exceed the Company's current total common stock equity.

Interest Rate Risk

     As of September 30, 2002, the Company has $16.3 million of Industrial Development/Pollution Control bonds outstanding, of which $10.8 million have an interest rate that floats monthly and $5.5 million floats every five years with the short-term credit markets. All other utility debt has a fixed rate. There are no interest lock or swap agreements in place. The Company has $46.5 million of consolidated temporary cash investments as of September 30, 2002, including $8.5 million of non-utility temporary cash investments, of which $8.1 million is related to Catamount. Also see non-utility risk factors below. Interest rate changes could also impact calculations affecting estimated pension and other benefit liabilities, thereby affecting pension and other benefit expenses and potentially require contributions to the trusts.

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Equity Market Risk

     As of September 30, 2002, the Company's pension trust holds marketable equity securities in the amount of

$33.2 million and its share of the Millstone Unit #3 decommissioning trust, in the amount of $2.1 million. The Company also maintains a variety of insurance policies in a Rabbi Trust, with a current value in the amount of $4.4 million, as of September 30, 2002, to support various supplemental retirement and deferred compensation plans. The current values of certain of these policies are affected by changes in the equity market. Therefore, changes in the equity market could affect pension expense as well as the Millstone Unit #3 decommissioning fund and the Rabbi Trust asset balances.

Credit Risk
     The Company has $16.9 million of letters of credit, supporting three series of tax-exempt pollution control/industrial development bonds, totaling $16.3 million. The earliest a series matures is 2009. These letters of credit expire on August 31, 2003 and need to be renewed. Without the support of the letters of credit, the bonds could become due.

     The Company has $17.5 million of first mortgage bonds and $75.0 million of second mortgage bonds maturing within the next five years. Access to the credit markets under reasonable terms is essential.

     The covenants covering the Company's second mortgage bonds contain limiting restrictions if those bonds receive a debt rating below BBB- from the rating agencies. The current ratings of the bonds from both, Fitch and Standard & Poor's are BBB- (stable). The limiting characteristics include certain restrictions on investments in non-regulated subsidiaries, the incurrence of indebtedness and the payment of dividends. Restrictions are dependent on meeting both a Fixed Charge Coverage and a Cumulative Cash Flow test. At September 30, 2002, both tests indicate current levels are acceptable.

     Based on the Company's credit rating, the Company could be in a position, whereby it would be required to collateralize for a net purchase position with ISO-New England. Effective May 1, 2002, under ISO-New England's financial assurance policy, requiring credit limit adherence, ISO-New England could require the Company to collateralize, if the Company is a net purchaser. Currently, the Company's BBB- credit rating allows a $2.5 million net purchase position at ISO-New England. If the Company exceeds the allowed net purchase position, the ISO-New England collateral requirement is three and one-half times the net purchase position, in either a letter of credit or cash. As of September 30, 2002, the Company's highest net purchase position with ISO-New England, under the financial assurance policy was $1.8 million, which is below the allowed threshold.

Non-Utility Risk Factors

     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.

Dependence on Governmental Policies

     The wind energy industry is highly dependent upon governmental policies and laws enacted to stimulate growth of clean renewable energy through tax credits and other incentive plans, including mandatory purchasing requirements by local utilities of renewable energy, including wind energy. While the trend worldwide is to increase the use of renewable energy sources, there is no assurance that any particular governmental policy or tax credit or incentive program will be continued in any jurisdiction where Catamount conducts business.

United States

     The U.S. Congress has enacted a production tax credit, which provides owners of wind energy projects a credit of 1.8 cents/kWh produced by any wind energy project installed and in operation by December 31, 2003. This credit may be earned by such eligible projects for the first 10 years of each project's life. Continued growth of the U.S. wind energy industry depends upon this tax credit being extended beyond December 2003, and depends upon an adequate market of investors who can utilize this credit efficiently. While bills containing extensions for an additional three years have been passed in both houses of the U.S. Congress, there is no assurance that such bills will be enacted into law and that the tax credit will be so extended. There are currently 12 U.S. states that have some form of mandatory renewable energy purchase requirements by utilities located in their respective states. Several U.S. states have other incentive and grant programs to promote renewab le energy. There is no assurance that any such program will be extended when each expires and there is no assurance that other states will follow the lead in promoting mandatory purchasing schemes.

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Europe

     The European Union ("EU") Renewable Energy Directive, formally adopted in September 2001, establishes national targets that would collectively result in renewable energy contributing 12 percent of the gross electricity consumed by the EU's 15 member countries in 2010 and a long-term goal of 22 percent. There can be no assurances as to how EU countries will implement and maintain policies related to the Renewable Energy Directive. Further, revenues generated in Catamount's targeted European markets are expected to be derived from renewable energy electricity purchases, which are currently required by national law. Support for renewable energy could diminish in any or all of these countries, resulting in the repeal of these national laws.

Regulation in the United States

     The electric utility industry in the U.S. remains highly regulated and subject to energy and environmental laws at the federal, state and local levels. Catamount's operations are currently unregulated by the federal and state electric industry regulators, despite the fact that Catamount is a wholly owned subsidiary of the Company. In addition, electric generation projects are subject to federal, state and local laws and administrative regulations, which govern the geographic location, zoning, land use and operation of plants and emissions produced by said plants. There is no guarantee that Catamount's operations will remain unregulated and may be subject to federal, state and local regulations in the future.

Market Acceptance

     Catamount's future success is dependent on the acceptance of wind power as an energy source by large producers, utilities, and other purchasers of electricity. Historically, the wind energy industry had a reputation for numerous problems relating to the failure of many wind-power generating facilities developed in the early 1980s to perform acceptably. In addition, many potential customers believe that wind energy is an unpredictable and inconsistent resource, is uneconomic compared to other sources of power and does not produce stable voltage and frequency. Although Catamount believes that these concerns may be adequately addressed in the near-term, there is no guarantee of wind power acceptance by potential customers as an energy source.

Reliance on Third-Party Equipment Vendors

     Currently less than 10 major wind turbine generating ("WTG") manufacturers are serving the worldwide wind energy market. In the recent past, several of these manufacturers have been subject to financial difficulties, mergers and industry consolidation. Because customer demand for WTGs fluctuates based upon market conditions, there is no assurance that manufacturing capacity will be available to meet expected increases in demand at any one time. Further, there is no assurance that key components and parts will be available to service WTGs, which could adversely impact Catamount's operations.

Foreign Operations

     Catamount currently owns investments in the UK and Germany and intends on developing wind energy projects in targeted European countries. Catamount's business may be affected by fluctuations in currency exchange rates, governmental currency controls, changes in various regulatory requirements, political and economic changes and disruptions, difficulties in managing foreign operations, including collections, and possible adverse tax consequences.

Interest Rate Risk

     Catamount has a variable rate revolving credit/term loan facility. Catamount expects to significantly pay-down the outstanding debt within the next six months, thereby reducing its exposure to interest rate risk. There are no interest lock or swap agreements in place. Catamount also maintains temporary cash investment accounts to meet its liquidity needs. As of September 30, 2002, the balance in those accounts is $8.1 million.

Credit Exposure

     Recent events including uncertainties concerning the operations of the wholesale markets and the demise of major wholesale power marketing companies have increased credit exposure in the energy industry and specifically with unregulated energy companies. Obtaining or renewing corporate credit facilities is challenging and there is no guarantee credit will be either extended or renewed. Catamount is negotiating a two-year extension of its existing revolving credit facility but there is no guarantee the facility will be extended and that Catamount would be able to find a replacement corporate credit facility.

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Item 4. CONTROLS AND PROCEDURES

     As of November 11, 2002, an evaluation was performed under the supervision and with the participation of the Company's management, including the President and Chief Executive Officer and Senior Vice President, Chief Financial Officer and Treasurer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures. Based on that evaluation, the Company's management, including the President and Chief Executive Officer and Senior Vice President, Chief Financial Officer and Treasurer, concluded that the Company's disclosure controls and procedures were effective in ensuring that material information relating to the Company with respect to the period covered by this report was made known to them. There have been no significant changes in the Company's internal controls or in other factors that could significantly affect internal controls subsequent to November 11, 2002.

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PART II - OTHER INFORMATION

Item 1.		Legal Proceedings.
	The Company is involved in litigation in the normal course of business, which the Company does not believe will have a material adverse effect on the financial position or results of operations, except as otherwise disclosed herein.
Item 2.		None.
Item 3.		None.
Item 4.		None.
Item 5.		(a)	William V. Boettcher resigned from the Company's Board of Directors effective October 4, 2002.
Item 6.		Exhibits and Reports on Form 8-K.
		(a)	Exhibits
			99.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
			99.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
		(b)	Dated October 7, 2002 Form 8-K re: Company's Amended By-Laws.
			Dated August 13, 2002 Form 8-K re: A current report containing two exhibits: Statements of Robert H. Young and Jean H. Gibson Regarding the Facts and Circumstances Relating to Exchange Act Filings.
			Dated August 23, 2002 Form 8-K re: A current report containing two exhibits: Statements of Robert H. Young and Jean H. Gibson Regarding the Facts and Circumstances Relating to Exchange Act Filings.

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SIGNATURES

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

	CENTRAL VERMONT PUBLIC SERVICE CORPORATION
	(Registrant)
By	/s/ Jean H. Gibson
	Jean H. Gibson Senior Vice President, Principal Financial Officer, and Treasurer

Dated    November 13, 2002   

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CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Robert H. Young, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Central Vermont Public Service Corporation (the "Registrant");
2.	Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
3.	Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this quarterly report;
4.	The Registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
	a)	designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
	b)	evaluated the effectiveness of the Registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and
	c)	presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.	The Registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of Registrant's board of directors:
	a)	all significant deficiencies in the design or operation of internal controls which could adversely affect the Registrant's ability to record, process, summarize and report financial data and have identified for the Registrant's auditors any material weaknesses in internal controls; and
	b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant's internal controls; and
6.	The Registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: November 13, 2002

/s/ Robert H. Young        
Chief Executive Officer

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CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Jean H. Gibson, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Central Vermont Public Service Corporation (the "Registrant");
2.	Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
3.	Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this quarterly report;
4.	The Registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
	a)	designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
	b)	evaluated the effectiveness of the Registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and
	c)	presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.	The Registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of Registrant's board of directors:
	a)	all significant deficiencies in the design or operation of internal controls which could adversely affect the Registrant's ability to record, process, summarize and report financial data and have identified for the Registrant's auditors any material weaknesses in internal controls; and
	b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant's internal controls; and
6.	The Registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: November 13, 2002

/s/ Jean H. Gibson         
Chief Financial Officer

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EXHIBIT INDEX

Exhibit Number	Exhibit Title
99.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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EX-99

Exhibit 99.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

            In connection with the Quarterly Report of Central Vermont Public Service Corporation (the "Company") on Form 10-Q for the period ending September 30, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I Robert H. Young, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge and belief:

            (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

            (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Robert H. Young        
Robert H. Young
Chief Executive Officer
November 13, 2002

EX-99

Exhibit 99.2

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

            In connection with the Quarterly Report of Central Vermont Public Service Corporation (the "Company") on Form 10-Q for the period ending September 30, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I Jean H. Gibson, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge and belief:

            (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

            (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Jean H. Gibson         
Jean H. Gibson
Chief Financial Officer
November 13, 2002