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, 2001    

|     |      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, 2001 there were outstanding 11,565,383 shares of Common Stock, $6 Par Value.

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Form 10-Q Table of Contents
PART I.		FINANCIAL INFORMATION		Page
Item 1.	Financial Statements
		Consolidated Statement of Income and Retained Earnings for the three and nine    months ended September 30, 2001 and September 30, 2000		3
		Consolidated Balance Sheet as of September 30, 2001 and December 31, 2000		4
		Consolidated Statement of Cash Flows for the nine months ended September 30, 2001    and September 30, 2000		5
		Notes to Consolidated Financial Statements		6
Item 2.	Management's Discussion and Analysis of Financial Condition and    Results of Operations		16
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		28
PART II.		OTHER INFORMATION		29
SIGNATURE				30

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
PART I - FINANCIAL INFORMATION

Item 1. Financial Statements
CONSOLIDATED STATEMENT OF INCOME AND RETAINED EARNINGS
(Dollars in thousands, except per share amounts)
(Unaudited)

	Three Months Ended		Nine Months Ended
	September 30		September 30
	2001	2000		2001	2000
Operating Revenues	$75,135	$73,947		$227,049	$247,763
Operating Expenses
Operation
Purchased power	36,070	42,463		110,444	140,471
Production and transmission	6,473	6,319		18,456	19,634
Other operation	10,029	10,785		32,152	31,647
Maintenance	4,373	4,074		13,575	10,307
Depreciation	4,261	4,179		12,774	12,685
Other taxes, principally property taxes	2,904	2,827		8,915	8,670
Taxes on income	3,419	347		9,482	6,755
Total operating expenses	67,529	70,994		205,798	230,169
Operating Income	7,606	2,953		21,251	17,594
Other Income and Deductions
Equity in earnings of affiliates	699	812		2,057	2,289
Allowance for equity funds during construction	11	14		44	57
Other income, net	(2,108)	8,061		(9,406)	6,604
Benefit (provision) for income taxes	868	(3,235)		4,043	(2,412)
Total other income and deductions, net	(530)	5,652		(3,262)	6,538
Total Operating and Other Income	7,076	8,605		17,989	24,132
Interest Expense
Interest on long-term debt	3,228	3,613		9,715	10,802
Other interest	107	198		325	328
Allowance for borrowed funds during construction	(6)	(8)		(22)	(33)
Total interest expense, net	3,329	3,803		10,018	11,097
Net Income Before Extraordinary Charge	3,747	4,802		7,971	13,035
Extraordinary Charge Net of Taxes	182	-		182	-
Net Income	3,565	4,802		7,789	13,035
Retained Earnings at Beginning of Period	76,975	74,052		78,423	72,371
Retained Earnings before Dividends	80,540	78,854		86,212	85,406
Cash Dividends Declared
Preferred Stock	424	-		1,272	1,335
Common Stock	2,543	2,536		7,627	7,586
Total dividends declared	2,967	2,536		8,899	8,921
Other Adjustments	(22)	81		238	(86)
Retained Earnings at End of Period	$77,551	$76,399		$ 77,551	$  76,399
Earnings Available For Common Stock	$    3,141	$   4,357		$   6,517	$  11,700
Average Shares of Common Stock Outstanding - basic	11,554,588	11,502,433		11,544,227	11,482,006
Average Shares of Common Stock Outstanding - diluted	11,554,588	11,502,433		11,786,776	11,482,006
Earnings Per Share of Common Stock-Basic	$     .27	$       .38		$       .56	$      1.02
Earnings Per Share of Common Stock-Diluted	$     .27	$       .38		$       .55	$      1.02
Dividends Paid Per Share of Common Stock	$     .22	$       .22		$       .66	$        .66

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

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

	September 30	December 31
	2001	2000
Assets
Utility Plant, at original cost	$483,403	$478,324
Less accumulated depreciation	195,387	183,828
	288,016	294,496
Construction work in progress	18,220	15,197
Nuclear fuel, net	986	1,283
Net utility plant	307,222	310,976
Investments and Other Assets
Investments in affiliates, at equity	24,173	24,527
Non-utility investments	52,212	46,591
Non-utility property, less accumulated depreciation	2,418	2,172
Total investments and other assets	78,803	73,290
Current Assets
Cash and cash equivalents	49,756	47,986
Special deposits	122	118
Accounts receivable, less allowance for uncollectible accounts             ($2,351 in 2001 and $1,655 in 2000)	24,159	25,006
Unbilled revenues	12,237	17,142
Materials and supplies, at average cost	4,054	3,702
Prepayments	1,533	2,593
Other current assets	5,401	6,511
Total current assets	97,262	103,058
Regulatory Assets	34,440	45,797
Other Deferred Charges	9,555	6,717
Total Assets	$527,282	$539,838
Capitalization and Liabilities
Capitalization
Common stock, $6 par value, authorized 19,000,000 shares;                Outstanding 11,785,848 shares	$  70,715	$  70,715
Other paid-in capital	47,861	45,810
Accumulated other comprehensive income	(2,019)	(269)
Deferred compensation plans - employee stock ownership plans	(1,669)	(358)
Treasury stock (227,538 shares, and 277,868, respectively, at cost)	(2,930)	(3,624)
Retained Earnings	77,551	78,423
Total Common Stock Equity	189,509	190,697
Preferred and preference stock	8,054	8,054
Preferred stock with sinking fund requirements	15,000	16,000
Long-term debt	159,704	152,975
Capital lease obligations	13,208	13,978
Total capitalization	385,475	381,704
Current Liabilities
Current portion of long - term debt	5,194	4,205
Accounts payable	4,148	6,407
Accounts payable - affiliates	9,974	13,523
Accrued income taxes	443	1,428
Dividends declared	2,967	2,532
Nuclear decommissioning costs	2,325	2,214
Disallowed purchased power costs	0	2,934
Other current liabilities	18,759	23,117
Total current liabilities	43,810	56,360
Deferred Credits
Deferred income taxes	38,038	43,779
Deferred investment tax credits	5,756	6,049
Nuclear decommissioning costs	13,381	14,737
Other deferred credits	40,822	37,209
Total deferred credits	97,997	101,774
Commitments and Contingencies
Total Capitalization and Liabilities	$527,282	$539,838

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

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

	Nine Months Ended        September 30
	2001	2000
Cash Flows Provided (Used) By:
Operating Activities
Net income	$   7,789	$   13,035
Adjustments to reconcile net income to net cash       provided by operating activities
Extraordinary Charge	182	-
Equity in earnings of affiliates	(2,057)	(2,289)
Dividends received from affiliates	2,050	3,301
Equity in earnings from non-utility investment	(3,900)	198
Distribution of earnings from non-utility investments	2,737	3,040
Depreciation	12,774	12,685
Regulatory Asset write-off	9,000	-
Investment Write-down	1,963	-
Amortization of capital leases	817	817
Deferred income taxes and investment tax credits	(5,399)	(3,915)
Net deferral and amortization of nuclear replacement            energy and maintenance costs	(3,984)	4,707
Amortization of conservation and load management costs	2,590	4,004
Decrease in accounts receivable and unbilled revenues	7,842	22,194
Decrease in accounts payable	(6,606)	(10,281)
Decrease in accrued income taxes	(1,263)	(2,188)
Change in other working capital items	(5,119)	(350)
Other, net	3,369	3,285
Net cash provided by operating activities	22,785	48,243
Investing Activities
Construction and plant expenditures	(10,674)	(10,307)
Conservation and load management expenditures	(413)	(908)
Return of capital	140	267
Non-utility investments	(7,697)	(4,247)
Other investments, net	(414)	1
Net cash used for investing activities	(19,058)	(15,194)
Financing Activities
Short-term debt, net	(11)	2
Long-term debt, net	6,730	1,789
Common and preferred dividends paid	(8,464)	(8,912)
Reduction in capital lease obligations	(817)	(817)
Sale of treasury stock	627	505
Other	(22)	(209)
Net cash used by financing activities	(1,957)	(7,642)
Net Increase In Cash and Cash Equivalents	1,770	25,407
Cash and Cash Equivalents at Beginning of Year	47,986	35,461
Cash and Cash Equivalents at End of Year	$   49,756	$   60,868
Supplemental Cash Flow Information
Cash paid during the period for:
Interest (net of amounts capitalized)	$     10,307	$   10,695
Income taxes (net of refunds)	$     12,559	$   14,951

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 - Accounting Policies

     The Company's significant accounting policies are described in Note 1 of Notes to Consolidated Financial Statements included in its 2000 Annual Report on Form 10-K filed with the Securities and Exchange Commission. For interim reporting purposes, the Company follows these same basic accounting policies, but considers each interim period as an integral part of an annual period. In the third quarter of 2001, Management determined that it's New Hampshire subsidiary Connecticut Valley Electric Company ("Connecticut Valley") is again subject to cost based rate making and qualifies for the application of Statement of Accounting Standards ("SFAS") No. 71, Accounting for the Effects of Certain Types of Regulation, ("SFAS No. 71"). See Note 4 - New Hampshire Retail Rates below for detail regarding the application of FAS No. 71 at Connecticut Valley.

     The financial information included herein is unaudited; however, such information reflects all adjustments (consisting of normal recurring accruals) which are, in the opinion of management, necessary for a fair statement of results for the interim periods.

New Accounting Pronouncements

Derivative Instruments: On January 1, 2001, the Company adopted SFAS No. 133 (subsequently amended by SFAS No.'s 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. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting.

     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 Vermont Public Service Board ("PSB") approved an Accounting Order which allows the fair valuation adjustment of this contract to be deferred on the balance sheet as either a deferred asset or liability. In the first quarter of 2001, this derivative had an estimated fair market value of approximately a $7.5 million unrealized loss which was recorded on the Consolidated Balance Sheet along with an offsetting deferred asset. In the second quarter of 2001, the Company adjusted its valuation methodology for this derivative which resulted in a fair market value of approximately a $1.4 million unrealized loss. The fair market value remained the same for the third quarter of 2001. The unrealized loss is included in deferred credits and other deferred charges in the accompanying balance sheet.

Goodwill and Other Intangible Assets: In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 142, Goodwill and Other Intangible Assets ("SFAS No. 142"), effective for fiscal years beginning after December 15, 2001. Under the new rules, goodwill and intangible assets deemed to have indefinite lives, will no longer be amortized, but will be subject to annual impairment tests in accordance with SFAS 142. Other intangibles will continue to be amortized over their useful lives. The Company has not yet quantified the impacts, if any, of adopting SFAS No. 142 on its financial statements.

Asset Retirement Obligations: In July 2001, the FASB approved the issuance of SFAS No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143"). This statement provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of long-lived assets and requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The Company has identified potential retirement obligations associated with the decommissioning of its nuclear facilities but has not yet completed its assessment. This statement is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Company has not yet quantified the impacts, if any, of adopting SFAS No. 143 on its financial statements.

Impairment or Disposal of Long-Lived Assets: In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS No. 144") which replaces SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of ("SFAS No. 121"). This

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statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 retains the requirements of SFAS No. 121 to recognize an impairment loss when the carrying amount of a long-lived asset is not recoverable and provides for alternative cash flow measurement methods when more than one course of action is available for recovery of the carrying amount of the asset. The provisions of SFAS No. 144 are effective for financial statements issued for fiscal years beginning after December 15, 2001 and, generally are to be applied prospectively. The Company has not yet quantified the impacts, if any, of adopting SFAS No. 144 on its financial statements.

Note 2 - Regulatory Assets

     Certain costs are deferred and amortized in accordance with authorized or expected ratemaking treatment. The major components of regulatory assets reflected in the Consolidated Balance Sheet are as follows (dollars in thousands):

	September 30	December 31
	2001	2000
Conservation and load management	$ 4,911	$10,212
Restructuring costs	84	2,472
Nuclear refueling outage costs	5,912	1,928
Income taxes	6,411	7,047
Year 2000 costs and technologies initiatives	37	2,322
Dismantling costs:
Maine Yankee nuclear power plant	10,894	11,505
Connecticut Yankee nuclear power plant	4,812	5,446
Hydro-Quebec arbitration costs	0	2,531
Unrecovered plant and regulatory study costs	1,361	1,510
Other regulatory assets	18	824
Total Regulatory Assets	$34,440	$45,797

     As a result of the June 26, 2001 approved rate order, the Company wrote-off $9.0 million (pre-tax) of regulatory assets, in the second quarter of 2001, related to Conservation and load management, Year 2000 costs and technologies initiatives, Restructuring costs, and other costs as agreed to with the PSB. In addition, the Company agreed that all amounts collected based on the award issued by the Hydro-Quebec arbitration panel would be applied first to reduce the balance of the deferred costs related to the ice storm arbitration, with the remaining balance applied to reduce other regulatory asset accounts as specified by the Vermont Department of Public Service ("DPS") and approved by the PSB. See Note 4 for discussion of the Vermont rate case settlement.

     In July 2001, the Company received its share of the settlement with Hydro-Quebec of $4.3 million, and has 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, which agreement is subject to approval by the PSB. Currently, the remaining $1.6 million balance is included as a deferred credit on the Company's Consolidated Balance Sheet. See Note 6 for discussion of the Hydro-Quebec contract.

     In addition to the Company's approved rate order, Vermont Yankee and Millstone Unit #3 had scheduled refueling outages during the first six months of 2001. During regular nuclear refueling outages, the incremental costs attributable to replacement energy purchased from ISO-New England or other parties in New England and maintenance costs are deferred and amortized ratably to expense until the next regularly scheduled refueling outage.

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Note 3 - Investments in Affiliates

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

Vermont Yankee Nuclear Power Corporation:

	Three Months Ended September 30		Nine Months Ended September 30
	2001	2000	2001	2000
Operating revenues	$ 37,867	$ 44,648	$ 135,862	$ 130,042
Operating income	$   3,105	$   4,263	$     9,187	$   12,173
Net income	$   1,641	$   1,560	$     4,765	$     4,942
Company's equity in net income	$      521	$      481	$     1,493	$     1,541

Vermont Electric Power Company:

	Three Months Ended September 30		Nine Months Ended September 30
	2001	2000	2001	2000
Operating revenues	$ 6,806	$ 7,012	$ 22,524	$ 21,151
Operating income	$    712	$    632	$   2,250	$   2,001
Net income	$    230	$    309	$      782	$      892
Company's equity in net income	$    135	$    162	$      435	$      462

Note 4 - 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 filed for a 6.6%, or $15.4 million per annum, general rate increase on September 22, 1997 to become effective June 6, 1998 to offset increasing costs of providing service. Approximately $14.3 million, or 92.9%, of the rate increase request was to recover scheduled contractual increases in the cost of power the Company purchases from Hydro-Quebec.

     In response to the Company's September 1997 rate increase filing, the PSB decided to appoint an independent investigator to examine the Company's decision to buy power from Hydro-Quebec. The Company made a filing with the PSB stating that the PSB as well as other parties should be barred from reviewing past decisions because the PSB already examined the Company's decision to buy power from Hydro-Quebec in a 1994 rate case in which the Company was penalized for "improvident power supply management." During February 1998, the DPS filed testimony in opposition to the Company's retail rate increase request. The DPS recommended that the PSB instead reduce the Company's then current retail rates by 2.5% or $5.7 million. The Company sought, and the PSB granted, permission to stay this rate case and to file an interlocutory appeal of the PSB's denial of the Company's motion to preclude a re-examination of the Company's Hydro-Quebec contract in 1991. The Company argued its position before the Vermont Supreme Court.

     On June 12, 1998, the Company filed with the PSB for a 10.7% retail rate increase that supplanted the September 22, 1997 rate increase request of 6.6%, to be effective March 1, 1999. On October 27, 1998, the Company reached an agreement with the DPS regarding the June 1998 retail rate increase request providing for a temporary rate

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increase in the Company's Vermont retail rates of 4.7% or $10.9 million on an annualized basis beginning with service rendered on or after January 1, 1999. The agreement was approved by the PSB on December 11, 1998.

     The 4.7% rate increase was subject to retroactive or prospective adjustment upon future resolution of issues arising under the Hydro-Quebec and the Vermont Joint Owners ("VJO") Power Contract. The agreement temporarily disallowed approximately $7.4 million (based on 1999 power costs) of the Company's purchased power costs under the VJO Power Contract. As a result of the 4.7% rate increase agreement, during the fourth quarters of 1998 and 1999, the Company recorded pre-tax losses of $7.4 million and $2.9 million, respectively, for disallowed purchased power costs, representing the Company's estimated under recovery of power costs, prior to further resolution, under the VJO Power Contract for 1999 and the first quarter of 2000, respectively. In 2000, an additional $11.5 million pre-tax loss was recorded for the estimated under recovery of Hydro-Quebec power costs for the second, third and fourth quarters of 2000, and the first quarter of 2001. In the first quarter of 2001, an additional $2.9 million pre-tax loss was recorded for the estimated under recovery of Hydro-Quebec power costs for the second quarter of 2001. In the second quarter of 2001, the Company reversed its $2.9 million pre-tax liability related to estimated under recovery of Hydro-Quebec power costs and discontinued the accrual based on the favorable outcome of the Company's June 26, 2001 rate order, which is described below.

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

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

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

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

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

     Deseasonalized Rates: On June 8, 2000, the PSB approved the Company's request to end the winter-summer rate differential and, therefore, the Company now has flat rates throughout a given year. Winter rates were reduced, while summer rates were increased. The rate design change was revenue neutral over a 12-month period. The additional 2000 revenues, resulting from implementing this change in mid-year, were applied to reduce or eliminate certain regulatory assets, as ordered by the PSB.

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

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     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 which required Connecticut Valley to give notice to cancel its 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 a 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 discussed above, on March 22, 1999 the NHPUC issued an Order which 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 Federal Energy Regulatory Commission ("FERC") exit fee, but at the same time to freeze Connecticut Valley's rates at their December 31, 1997 level which does not enable Connecticut Valley to recover all of these power costs.

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

     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

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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 were 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 are being collected during 2001 along with 2001 power costs. The NHPUC held a hearing on April 7, 2000 to review the 12.3% increase that would raise $1.6 million of revenues in 2000. The NHPUC issued an order approving the rates as temporary effective May 1, 2000.

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

     On March 23, 2001, Connecticut Valley filed a request with the NHPUC to make the Interim FAC/PPCA rates permanent and a decision is still pending.

     In the third quarter of 2001, Management determined that Connecticut Valley is again subject to cost based rate making and qualifies for the application of SFAS No. 71. This decision was based on the favorable Supreme Court decision of November 27, 2000 and the subsequent denial of the NHPUC's appeal 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.

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 power and transmission service to Connecticut Valley and a notice of cancellation of the rate schedule under which it is provided (contingent upon the recovery of the stranded costs that would result from the cancellation of this rate schedule). In December 1997, the FERC rejected the Company's proposal to recover stranded costs through the imposition of a surcharge on its transmission tariff, but indicated that it would consider an exit fee mechanism for collecting stranded costs. The FERC denied the Company's motion for a rehearing regarding the surcharge proposal, so the Company filed a request with the FERC for an exit fee mechanism to collect the stranded costs resulting from the cancellation of the service to Connecticut Valley.

     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 Company had requested an exit fee of approximately $95.0 million in nominal dollars. 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.

     The ALJ's Initial Decision is subject to review and approval by the FERC. If the Company is unable to obtain approval by the FERC, and if Connecticut Valley is forced to terminate its relationship as a wholesale customer of the Company, it is possible that the Company would be required to recognize a pre-tax loss under this contract totaling approximately $44.7 million as of December 31, 2000. The Company would also be required to write-off approximately $1.4 million (pre-tax) in regulatory assets associated with its wholesale business as of September 30,

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2001. 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 include the cost of the exit fee in rates. However, if Connecticut Valley is unable to recover its costs in its rates, Connecticut Valley would be required to recognize the loss discussed above.

     An adverse resolution of the FERC and New Hampshire proceedings would have a material adverse effect on the Company's results of operations and cash flows. In addition to its efforts before the FERC, Connecticut Valley continues to work for a negotiated settlement with parties to the New Hampshire restructuring proceeding and the NHPUC.

     The Company cannot predict the ultimate outcome of these matters.

Wheelabrator Power Contract: Connecticut Valley purchases power from several Independent Power Producers ("IPP's"), who own qualifying facilities as defined by the Public Utility Regulatory Policies Act of 1978. In 2000, under long-term contracts with these qualifying facilities, Connecticut Valley purchased 39,998 mWh, 94% of which was purchased from Wheelabrator Claremont Company, L.P., ("Wheelabrator") who owns a solid waste plant. Connecticut Valley had filed a complaint with FERC stating its concern that Wheelabrator has not been a qualifying facility since the plant 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. The Company filed a request for rehearing with the FERC on March 13, 1998, which was denied. Subsequently, Connecticut Valley appealed to the D.C. Circuit Court of Appeals, which denied the Company's appeal, but indicated that the Company could seek relief from the NHPUC. On May 12, 2000, the Company filed a petition with the NHPUC seeking 1) to amend the contract to permit purchase of net, rather than gross, output of the plant 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. A Prehearing Conference was held before the NHPUC on January 4, 2001, at which time each party provided preliminary position statements with regard to the petition. In February and March 2001 the parties filed briefs on the legal issues and Wheelabrator filed a motion to dismiss. The Company cannot predict when the NHPUC will issue a decision on the legal issues or the motion to dismiss or on the outcome of this matter.

Note 5 - Environmental

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

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

     The Company is an amalgamation of more than 100 predecessor companies. Those companies engaged in various operations and activities prior to being merged into the Company. At least two of these companies were involved in the production of gas from coal to sell and distribute to retail customers at four different locations. The Company discontinued these activities in the late 1940's or early 1950's. 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.

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     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 1980's and early 1990's to determine the magnitude and extent of the contamination. After completing its preliminary investigation, the Company engaged a consultant to assist in evaluating clean-up methodologies and provide cost estimates. Those studies indicated the cost to remediate the site would be approximately $5.0 million. This was charged to expense in the fourth quarter of 1992. 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 1940's, 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 April 2000, the Company presented the assessment findings to the States of New Hampshire and Vermont and the town of Brattleboro. The State of Vermont concluded that additional semi-annual site monitoring is necessary and that the Company must develop a corrective action plan. The Company recently submitted a corrective action plan to the State of Vermont and expects plan approval shortly. The Company will implement this plan which includes provisions for periodic groundwater monitoring and institutional controls. The Company recently 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. At this time the Company has not finalized an estimate of its potential liability at this site.

Dover, New Hampshire, Manufactured Gas Facility In late 1999, the Company was contacted by Public Service of New Hampshire ("PSNH") with respect to this site. PSNH alleges the Company is partially liable for remediation of this site. PSNH's allegation is 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 proposed, and PSNH accepted, an agreement that calls for an environmental mediator to assist in a non-binding evaluation of the Company's liability. In December 2000, PSNH submitted a work plan to the State of New Hampshire for further investigation of this site. The Company agreed, with reservations, to participate on a limited basis in the development and completion of the work plan since the State of New Hampshire considers the Company, along with others, as potentially responsible parties at the site. The Company, PSNH and Keyspan Energy hired a contractor which completed the fieldwork in October 2001. A report will be published and submitted to the State of New Hampshire in late 2001 or early 2002. Shortly thereafter, the Company and others will begin evaluating remediation options for the site.

     A mediator on the issue of liability was chosen in April 2001 and the first phase of mediation, or "Phase I", 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 others in a "Phase II" mediation process. The subject of the Phase II mediation was the liability of other potentially responsible parties at the site, in particular those that owned the property after Twin State and PSNH. The Phase II mediation process did not achieve the goal of a general agreement on liability between the participants. The cost of the remediation, the extent to which there are other potentially liable parties, and the amount of insurance recovery are yet to be determined. At this time, the Company is unable to estimate its potential liability at this site.

     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.

     As of September 30, 2001, a reserve of $9.4 million exists which represents management's best estimate of the costs to remediate the sites discussed above.

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Note 6 - Hydro-Quebec Power Contract

     The Company is purchasing varying amounts of power from Hydro-Quebec under the VJO contract through 2016. There are specific contractual step up provisions that provide that in the event any VJO member fails to meet its obligation under the contract with Hydro-Quebec, the balance of the VJO participants, including the Company, will "step up" to the defaulting party's share on a pro-rata basis. As of December 31, 2000 the Company's VJO obligation is approximately $937.0 million on a nominal basis over the term of the contract ending in 2016. The total VJO contract obligation on a nominal basis over the term of the contract is approximately $2.2 billion.

     During January 1998, a significant ice storm affected parts of New York, New England and the Province of Quebec, Canada. This storm damaged major components of the Hydro-Quebec transmission system over which power is supplied to Vermont under the VJO Power Contract with Hydro-Quebec. This resulted in a 61-day interruption of a significant portion of scheduled contractual energy deliveries into Vermont. The ice storm's effect on Hydro-Quebec's transmission system caused the VJO to examine Hydro-Quebec's overall reliability and ability to deliver energy. On the basis of that examination, the VJO determined that Hydro-Quebec had been and remained unable to make available capacity with the degree of firmness required by the VJO Power Contract. That determination prompted the VJO to initiate an arbitration proceeding. In the arbitration, the VJO sought to terminate the contract, recover damages associated with Hydro-Quebec's failure to comply with the contract, and recover capacity payments made during the period of non-delivery. In September 1999, an initial two weeks of hearings were held dealing primarily with issues of contract interpretation. Additional hearings dealing with technical issues were held in the second and third quarters of 2000.

     On April 17, 2001, the Company received a decision in the arbitration proceeding relating to the failure by Hydro-Quebec to deliver power during the outage in 1998. The decision stated that the long-term power supply contract between Hydro-Quebec and the Vermont utilities remains in effect, that Hydro-Quebec is required to reimburse the Vermont utilities for capacity payments made during the outage for power not delivered and ordered a refund to the VJO, valued at up to approximately $20.0 million plus interest, which amount would be adjusted downward to reflect either actual deliveries by Hydro-Quebec in the first quarter of 1998 or an agreement by the parties.

     In accordance with a PSB Accounting Order, the Company deferred legal, consulting and related costs associated with this arbitration of approximately $6.4 million at September 30, 2001. These deferred costs have been offset by incremental revenue of $3.8 million, resulting from the implementation of deseasonalized rates on July 1, 2000 through December 31, 2000, as directed by the PSB. As part of the Company's June 26, 2001 rate order, the Company agreed that all amounts collected based on the award issued by the arbitration panel, or any settlement agreement with Hydro-Quebec or any other party related to the Company's VJO contract power supply costs, shall be applied first to reduce the remaining balance of deferred costs related to the ice storm arbitration, with the remaining balance, if any, applied to reduce other regulatory asset accounts as specified by the DPS and approved by the PSB.

     On July 19, 2001, Hydro-Quebec and the VJO agreed to a final settlement of the arbitration issues. Under the settlement, the VJO will continue to receive power and energy from Hydro-Quebec under this contract through 2016. As part of the settlement, Hydro-Quebec made a $9.0 million payment to the VJO in July 2001, of which the Company's share was approximately $4.3 million. In the third quarter of 2001 the Company applied approximately $2.7 million to the remaining balance of the deferred costs related to the ice storm arbitration. On October 30, 2001, the Company filed a letter with the PSB summarizing its agreement with the DPS on application of the remaining $1.6 million of the Hydro-Quebec settlement to remaining regulatory assets, which agreement is subject to approval by the PSB. Currently, the remaining $1.6 million balance is included as a deferred credit on the Company's Consolidated Balance Sheet.

Note 7 - 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-supply projects in North America and Western Europe and Eversant Corporation ("Eversant", formerly SmartEnergy Services, Inc.) which pursues retail alliances to market energy and related products and services, engages in the sale of or rental of

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electric water heaters to customers in Vermont and New Hampshire and has a 18.4% ownership interest, on a fully diluted basis, in the Home Services Store ("HSS"), operating nationwide. On October 23, 2001, SmartEnergy Services, Inc. changed its name to Eversant Corporation. 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.

     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, 2001 and 2000, is as follows (dollars in thousands):

					Reclassification
	CV	CVEC			and Consolidating
Three months ended September 30	VT	NH	Catamount	Eversant	Other (1)	Entries	Consolidated
2001
Revenues from external customers	$ 70,137	$ 5,001	$     53	$   451	$    -	$  (507)	$ 75,135
Intersegment revenues	2,559	-	-	-	-	(2,559)	-
Net income (loss)	4,533	301	34	(1,304)	1	-	3,565
Total assets	458,940	12,935	54,418	4,390	320	(3,721)	527,282
2000
Revenues from external customers	$ 65,573	$ 8,377	$    145	$    645	$    -	$  (793)	$ 73,947
Intersegment revenues	2,946	-	-	-	-	(2,946)	-
Net income (loss)	2,043	2,323	492	(60)	4	-	4,802
Total assets	485,544	12,283	47,701	5,641	312	(4,942)	546,539

1. Includes a segment below the quantitative threshold.

					Reclassification
	CV	CVEC			and Consolidating
Nine months ended September 30	VT	NH	Catamount	Eversant	Other (2)	Entries	Consolidated
2001
Revenues from external customers	$211,272	$ 15,782	$   184	$ 1,493	$    -	$(1,682)	$227,049
Intersegment revenues	8,490	-	-	-	-	(8,490)	-
Net income (loss)	8,334	421	560	(1,533)	7	-	7,789
Total assets	458,940	12,935	54,418	4,390	320	(3,721)	527,282
2000
Revenues from external customers	$229,743	$ 18,026	$   370	$ 2,300	$    -	$(2,676)	$247,763
Intersegment revenues	9,403	-	-	-	-	(9,403)	-
Net income (loss)	12,469	2,169	789	(2,402)	10	-	13,035
Total assets	485,544	12,283	47,701	5,641	312	(4,942)	546,539

1. Includes a segment below the quantitative threshold.

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION

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

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 Operation) are forward looking statements intended to qualify for the safe-harbors from liability established by the Private Securities Reform Act of 1995. Statements made that are not historical facts are forward looking and, accordingly, involve estimates, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward looking statements. Actual results will depend, among other things, upon the actions of regulators, the outcome of litigation at the FERC involving the Company's regulated companies, the performance of the Vermont Yankee nuclear power plant, weather conditions, the performance of the Company's unregulated businesses, and the state of the economy in the areas served.

Earnings Overview

     The Company reported net income of $3.6 million, or $.27 per basic and diluted share of common stock, for the third quarter of 2001 compared to net income of $4.8 million, or $.38 per basic and diluted share of common stock, for the third quarter of 2000. A breakdown of the factors impacting third quarter 2001 earnings compared to third quarter 2000 earnings follows:

• higher utility revenues of $5.9 million after-tax, or $.50 per share of common stock, resulting from higher average retail revenues due to deseasonalized or equalized winter/summer rates beginning July 1, 2000 and the June 26, 2001 approved rate order which allowed for a 3.95% increase in retail rates beginning July 1, 2001;

• higher utility revenues of $0.7 million after-tax, or $.06 per share of common stock, resulting from a 1.8% (10,002mWh) increase in retail mWh sales;

• lower net power costs of $0.2 million after-tax, or $.03 per share of common stock;

• higher operating and other costs of $0.7 million after-tax, or $.06 per share of common stock, primarily related to higher life insurance expense;

• lower earnings in the third quarter of 2001 at Catamount Energy of $0.5 million after-tax, or $.04 per share of common stock;

• higher net losses in the third quarter of 2001 at Eversant Corporation ("Eversant", formerly SmartEnergy Services, Inc.) of $1.2 million after-tax, or $.11 per share of common stock, primarily related to a $1.1 million after-tax write-down of Eversant's investment in Home Service Store, Inc. ("HSS") bringing its remaining investment to $1.4 million;

• an extraordinary charge of $0.2 million, or $.02 per share of common stock, resulting from the application of Statement of Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation," ("SFAS No. 71") at the Company's New Hampshire subsidiary, Connecticut Valley Electric Company ("Connecticut Valley");

• third quarter 2000 nonrecurring income (with no comparable income in 2001) of $3.2 million after-tax, or $.28 per share of common stock, related to the successful conclusion of owners' litigation with Northeast Utilities over the Nuclear Regulatory Commission's 1996 shut down of the Millstone Unit #3 Nuclear Power Plant; and

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• third quarter 2000 nonrecurring income (with no comparable income in 2001) of $2.0 million after-tax, or $.18 per share of common stock, from the reversal of Connecticut Valley's provision for rate refund related to a favorable First Circuit Court of Appeals decision.

     For the nine months ended September 30, 2001 the Company had net income of $7.8 million, or $.56 per basic and $.55 per diluted share of common stock, compared to nine months ended September 30, 2000 net income of $13.0 million, or $1.02 per basic and diluted share of common stock.

     During the nine months ended September 30, 2001, the Company had a third quarter extraordinary charge of $0.2 million related to Connecticut Valley which is again subject to cost based rate making, and second quarter non-recurring items of $5.3 million after-tax, or $.46 per share of common stock, related to the June 2001 Vermont rate case settlement write-off; $1.7 million after-tax, or $.15 per share of common stock, favorable impact due to the elimination of under recovery of costs related to the Hydro-Quebec power contract; and $1.5 million, or $.13 per share of common stock, due to a one-time reversal of charges in ISO-New England. Excluding these items, the Company's pro-forma net income for the nine months ended September 30, 2001 was $10.1 million, or $.76 per basic and $.75 per diluted share of common stock. This compares to nine months ended September 30, 2000 pro-forma net income of $8.1 million, or $.60 per basic and diluted share of common stock, which excludes nonrecurring income related to the favorable Millstone Unit #3 settlement and the favorable Connecticut Valley First Circuit Court of Appeals decision.

     A breakdown of the factors impacting nine months 2001 earnings compared to the same period last year follows:

• higher utility revenues of $4.6 million after-tax, or $.40 per share of common stock, resulting from higher average retail revenues due to deseasonalized or equalized winter/summer rates beginning July 1, 2000 and the June 26, 2001 approved rate order which allowed for a 3.95% increase in retail rates beginning July 1, 2001;

• lower utility revenues of $0.6 million after-tax, or $.06 per share of common stock, resulting from a 0.9% (15,588 mWh) decrease in retail mWh sales;

• lower net power costs of $2.2 million after-tax, or $.19 per share of common stock, resulting from a one-time reversal of accrued power costs of $1.5 million after-tax, related to installed capacity ("ICAP") deficiency charges in ISO-New England and lower Vermont Yankee decommissioning costs;

• higher operating and other costs of $3.6 million after-tax, or $.31 per share of common stock, due to higher service restoration costs related to storm activity in the first quarter of 2001 and higher life insurance expense, offset by reduced interest expense due to maturity of First Mortgage Bonds;

• lower net losses in the first nine months of 2001 at Eversant of $0.9 million after-tax, or $.08 per share of common stock primarily related to Eversant's investment in Home Service Store, Inc. bringing its remaining investment to $1.4 million;

• the Company's June 26, 2001 rate order resulting in a net after-tax loss 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 and 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;

• an extraordinary charge of $0.2 million, or $.02 per share of common stock, resulting from the application of SFAS No. 71 at Connecticut Valley;

• third quarter 2000 nonrecurring income (with no comparable income in 2001) of $3.2 million after-tax, or $.28 per share of common stock, related to the successful conclusion of owners' litigation with Northeast Utilities over the Nuclear Regulatory Commission's 1996 shut down of the Millstone Unit #3 Nuclear Power Plant; and

• third quarter 2000 nonrecurring income (with no comparable income in 2001) of $1.7 million after-tax, or $.14 per share of common stock, from the reversal of Connecticut Valley's provision for rate refund related to a favorable First Circuit Court of Appeals decision.

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     Other factors affecting results for 2001 are described in the following Results of Operations.

Results of Operations

The major elements of the Consolidated Statement of Income are discussed below.

Operating revenues and megawatt-hour ("mWh") sales A summary of operating revenues and mWh sales for 2001 and 2000 is set forth below:

	Three Months Ended September 30
			Percentage			Percentage
	MWh Sales		Increase	Revenues (000's)		Increase
	2001	2000	(Decrease)	2001	2000	(Decrease)
Residential	224,451	217,652	3.1	$ 30,473	$ 25,365	20.1
Commercial	242,939	236,975	2.5	29,020	23,912	21.4
Industrial	103,579	106,374	(2.6)	8,555	7,808	9.6
Other retail	1,621	1,587	2.1	462	450	2.7
Total retail sales	572,590	562,588	1.8	$ 68,510	$ 57,535	19.1
Resale sales:
Firm	282	329	(14.3)	$      30	$      33	(9.1)
Entitlement	53,659	108,490	(50.5)	1,876	3,690	(49.2)
Alliance	0	80,000	(100.0)	0	2,837	(100.0)
Other	86,299	134,426	(35.8)	3,455	5,274	(34.5)
Total resale sales	140,240	323,245	(56.6)	5,361	11,834	(54.7)
Other revenues	-	-	-	1,264	4,578	(72.4)
Total	712,830	885,833	(19.5)	$ 75,135	$ 73,947	1.6

	Nine Months Ended September 30
			Percentage			Percentage
	MWh Sales		Increase	Revenues (000's)		Increase
	2001	2000	(Decrease)	2001	2000	(Decrease)
Residential	713,669	712,819	.1	$  92,947	$  90,333	2.9
Commercial	695,753	689,466	.9	81,580	76,268	7.0
Industrial	319,282	342,031	(6.7)	26,254	27,574	(4.8)
Other retail	4,749	4,725	.5	1,342	1,339	0.2
Total retail sales	1,733,453	1,749,041	(0.9)	$202,123	$195,514	3.4
Resale sales:
Firm	1,416	1,431	(1.0)	$     104	$     103	1.0
Entitlement	146,677	243,468	(39.8)	6,588	8,444	(22.0)
Alliance	0	530,800	(100.0)	0	19,347	(100.0)
Other	325,131	496,361	(34.5)	13,665	16,880	(19.0)
Total resale sales	473,224	1,272,060	(62.8)	20,357	44,774	(54.5)
Other revenues	-	-	-	4,569	7,475	(38.9)
Total	2,206,677	3,021,101	(27.0)	$227,049	$247,763	(8.4)

     Retail mWh sales for the third quarter of 2001 increased 1.8% compared to the third quarter of 2000, and related revenues increased $11.0 million, or 19.1% compared to last year. The favorable retail revenue variance is primarily related to a $9.9 million favorable price variance, of which $7.5 million is due to the favorable impact of deseasonalized rates which were deferred against regulatory assets in the third quarter of 2000 and $2.4 million related to the 3.95% rate increase which became effective July 1, 2001. Additionally, the 1.8% increase in volume mostly related to higher residential and commercial mWh sales resulted in a $1.1 million favorable impact for the third quarter of 2001 compared to the same period in 2000.

     For the nine months ended 2001, retail mWh sales decreased 0.9% or 15,588 mWh compared to the nine months ended 2000, primarily from the industrial sector. Retail revenues, however, increased $6.6 million or 3.4% primarily due to the favorable impact of deseasonalized rates in the third quarter of 2001 and the 3.95% rate increase which became effective July 1, 2001.

     Wholesale mWh sales for the third quarter of 2001 decreased 56.6%, and related revenues decreased 54.7% compared to last year mostly due to the discontinuance of the Company's alliance with Virginia Power and the conclusion of a long term contract which ended in late 2000. Alliance sales in 2000 were offset by short term purchases in 2000, which are included in the Net Purchased Power and Production Fuel Costs table below.

     For the nine months ended 2001 wholesale mWh sales decreased 62.8% or 798,836 mWh as a result of the discontinuance of the Company's alliance with Virginia Power, the conclusion of a long-term contract which ended

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in late 2000, and the scheduled 2001 Vermont Yankee refueling outage.

     Other revenues for the quarter and nine months ended September 30, 2001 compared to the same periods in 2000 were $3.3 million and $2.9 million lower due to the reversal of the provision for rate refunds related to a favorable First Circuit Court of Appeals decision allowing Connecticut Valley to recover it's power costs in rates. The reversal of the provision for rate refunds resulted in $3.2 million and $2.6 million nonrecurring income in 2000 for the third quarter and nine months ended, respectively.

Net Purchased Power and Production Fuel Costs The net cost components of purchased power and production fuel costs for the three and nine months ended September 30, 2001 and 2000 are as follows (dollars in thousands):

	Three Months Ended September 30
	2001		2000
	Units	Amount	Units	Amount
Purchased and produced:
Capacity (mW)	381	$ 21,365	400	$ 23,102
Energy (mWh)	687,926	14,705	839,551	19,361
Total purchased power costs		36,070		42,463
Production fuel (mWh)   Total purchased power and production fuel costs	71,923	913 36,983	94,996	1,292   43,755
Less entitlement and other resale sales (mWh)	139,958	5,331	322,916	11,801
Net purchased power and production fuel costs	619,891	$ 31,652	611,631	$ 31,954

	Nine Months Ended September 30
	2001		2000
	Units	Amount	Units	Amount
Purchased and produced:
Capacity (mW)	421	$ 62,881	421	$ 69,949
Energy (mWh)	2,116,610	47,563	2,829,054	70,522
Total purchased power costs		110,444		140,471
Production fuel (mWh)   Total purchased power and production fuel costs	245,682	2,388   112,832	346,257	3,347 143,818
Less entitlement and other resale sales (mWh)	471,808	20,253	1,270,629	44,671
Net purchased power and production fuel costs	1,890,484	$ 92,579	1,904,682	$ 99,147

     Total purchased power costs decreased $6.4 million for the third quarter of 2001 versus last year. The decrease is attributable to lower capacity costs of $1.7 million primarily related to lower Vermont Yankee decommissioning costs beginning July 1, 2001 and operational efficiencies at the plant. Additionally, purchased energy costs were $4.7 million lower due to the discontinuance of the Company's alliance with Virginia Power, higher output from Vermont Yankee which displaces higher priced short-term purchases, and lower costs related to ISO-New England.

     For the nine months ended September 30, 2001, purchased power costs deceased $30.0 million, of which $7.1 million is related to capacity costs and $22.9 million is related to purchased energy costs. The $7.1 million, or 10%, decrease in capacity costs compared to the nine months ended September 30, 2000 is related to the June 26, 2001 rate order which eliminated future disallowances for the under recovery of Hydro-Quebec power costs resulting in a $2.9 million favorable impact from the reversal of the accrual for estimated under recovery of Hydro-Quebec costs in the second quarter of 2001, with no accrual for future under recovery of those costs in the third quarter of 2001, the $2.5 million one-time reversal of accrued power costs for ICAP deficiency charges in ISO-New England due to resolution of a December 2000 FERC Order, and lower Vermont Yankee capacity costs. The $22.9 million, or 33%, decrease in purchased energy costs is primarily related to the discontinuance of the Company's alliance with Virginia Power.

     Production fuel costs decreased $0.4 million and $0.9 million for the third quarter and nine months ended September 30, 2001, respectively, compared to the same periods in 2000 primarily due to lower output.

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NUCLEAR MATTERS

The Company maintains a 1.7303% joint-ownership interest in Millstone Unit #3 and also owns a 31.3%, 2.0%, 2.0%, and 3.5% equity interest in Vermont Yankee, Maine Yankee, Connecticut Yankee and Yankee Atomic, respectively.

     Millstone Unit #3 On September 15, 1999, Northeast Utilities ("NU") announced its intent to auction its nuclear generating plants, including Unit #3. On August 7, 2000, the Connecticut Department of Public Utility Control announced that Dominion Resources, Inc. was the successful bidder in the auction. The sale to Dominion Nuclear Connecticut ("DNC"), a subsidiary of Dominion Resources Inc. became final on March 31, 2001. Unit #3 continues to be a jointly owned plant, and the Company is one of two minority owners. The total DNC share of Unit #3 is 93.4707%.

     Unit #3 began a scheduled nuclear refueling outage on February 3, 2001, which ended on March 31, 2001; 17 days beyond the scheduled outage. Pursuant to the terms of the July 27, 2000 settlement agreement with NU which resolved the Company's claims against NU relating to the extended 1996 outage of Unit #3, the Company received a payment of $0.3 million (pre-tax) from NU in July 2001 for the incremental energy costs associated with replacement power during the 17 day period beyond the scheduled outage. In addition, the settlement agreement limited the Company's obligation to pay NU for certain capital costs during the period in 2001 prior to the sale to DNC.

     Vermont Yankee The Vermont Yankee nuclear power plant, which provides more than one-third of the Company's power supply, began a scheduled refueling outage on April 27, 2001 which ended on May 20, 2001; 11 days shorter than budgeted. The previous refueling outage began on October 29, 1999 and the plant returned to service December 2, 1999. The next scheduled refueling outage is October of 2002.

     During 1999 and 2000 the Company and the other owners of Vermont Yankee accepted an initial bid and a revised bid for sale of the plant to AmerGen Energy Company ("AmerGen").

     On February 14, 2001, the Vermont Public Service Board ("PSB") issued its Order Dismissing Petition in Docket No. 6300, the proceeding in which the Company, along with Green Mountain Power ("GMP"), Vermont Yankee and AmerGen sought PSB approval of the sale of the Vermont Yankee nuclear plant to AmerGen. In this Order, the PSB determined that the proposed purchase price, as filed in November 2000, pursuant to a Memorandum of Understanding, did not reflect the fair market value of the plant and, therefore, the sale did not promote the general good of the State of Vermont. This ruling was consistent with the Company's position. The PSB dismissed the petition for approval in March 2001. The management of Vermont Yankee subsequently concluded that selling the plant at auction would provide the greatest benefit to the owners and consumers. The investment banking firm of JP Morgan was retained by Vermont Yankee as the exclusive financial advisor for the auction.

     On August 15, 2001, Vermont Yankee announced that a sales agreement had been reached with Entergy Corporation ("Entergy") for $180 million, representing $145 million for the plant and related assets and $35 million for nuclear fuel. Entergy will also assume decommissioning liability for the plant and its decommissioning trust fund. The agreement includes a purchase power contract with prices that generally range from 3.9 cents to 4.5 cents per kilowatt-hour subject to a "low market adjuster" that protects the current Vermont Yankee owner-utilities, including the Company and its power consumers, in the event power market prices drop significantly. On September 27, 2001, the Company filed testimony with the Vermont PSB in support of the sale. In an order entered October 26, 2001, the PSB granted intervention to several parties, which the Company did not oppose, and established a schedule which provides for discovery, hearings and final briefing by April 29, 2002. Certain of the intervenors are secondary purchasers of Vermont Yankee power, which are seeking adjustments in their power purchase contracts, and stockholders of Vermont Yankee, which are asserting dissenters' rights. The sale is also subject to other regulatory approvals including the Nuclear Regulatory Commission and the Securities and Exchange Commission.

     As a result of issues raised related to the cancelled AmerGen sale, Vermont Yankee has reached an agreement in principle with the Vermont Yankee Sponsors and their secondary power purchasers, the Vermont Department of Public Service ("DPS"), and the Federal Energy Regulatory Commission ("FERC") staff that reduces the Vermont Yankee cost of service the sponsors and the secondary purchasers will expect to pay through 2012. The agreement in principle is reflected in billings to sponsors and secondary purchasers, effective July 2001. The FERC approved the agreement on September 13, 2001.

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     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% of its required system capacity. The decommissioning effort continues per project plans. The original decommissioning contractor, Stone and Webster, has filed for bankruptcy. Maine Yankee claims against Stone and Webster are currently not resolved. The Company does not believe the impending bankruptcy will have a significant negative effect on the overall decommissioning effort, or its cost.

     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 3.0% of its required system capacity. Connecticut Yankee, which is operated by NU, continues to decommission the site. 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.

     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% of its required system capacity. As of July 2000, Yankee Atomic had collected from its sponsors sufficient funds based on a current forecast, to complete the decommissioning effort and to recover all other FERC approved costs of service. Therefore, Yankee Atomic discontinued billings to its sponsors pending the need to increase or decrease the funds available for the completion of its financial obligations including decommissioning. Such a change would require a FERC review and approval. Yankee Atomic is successfully decommissioning the site as planned.

     Maine Yankee, Connecticut Yankee and Yankee Atomic Decommissioning Costs Currently, costs billed to the Company by Maine Yankee, Connecticut Yankee and Yankee Atomic, 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 is estimated to be $10.9 million and $4.8 million, respectively, at September 30, 2001. These amounts are subject to ongoing review and revisions and are reflected in the accompanying Consolidated Balance Sheet both as regulatory assets and nuclear dismantling liabilities (current and non-current).

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

     Cogeneration/Independent Power Qualifying Facilities A number of Independent Power Producers ("IPPs") using hydroelectric, biomass, and wood-burning generation are currently producing energy that is allocated to the Company for the benefit of its customers by operation of Vermont law. The energy is purchased by a state appointed purchasing agent who purchases and redistributes the power to all Vermont utilities, for the benefit of customers, based on their pro-rata share of total Vermont retail kilowatthour sales for the previous calendar year.

     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 outlines 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 the Burlington Electric Department notified the PSB that they were withdrawing from the Petition but they will 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. The Company, the other moving utilities and the DPS had requested that the PSB issue an order requiring GMP's full participation in the PSB proceeding. The PSB declined to rule on the request but retained authority to require GMP to provide specific information or to submit any other specific filings.

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     On November 22, 2000, the IPPs filed dispositive motions in Docket No. 6270 urging the PSB to declare that it lacks jurisdiction to grant the relief sought by the Company's Petition. On January 8, 2001, the Company and the other petitioning utilities filed responses to the IPP's motions supporting the PSB's exercise of jurisdiction, as called under the Petition. The DPS also made a filing in support of jurisdiction. On June 1, 2001, the PSB Hearing Officer issued a Proposal for Decision ("PFD") on the PSB's jurisdiction to consider the Petition. The PFD recommended that the PSB find that it has jurisdiction to consider the relief sought under the Petition but that the PSB may be precluded from issuing orders reducing the lengths of a Purchasing Agent contract or requiring buy-outs or buy-downs. Docket participants filed comments on the PFD. On September 18, 2001 the PSB issued an Order regarding jurisdiction in which it adopted the conclusions of the Hearing Officer's PFD and found that the PSB has jurisdiction to consider five of the seven claims outlined in the original Petition.

     The IPPs also filed a related proceeding in the Washington County Superior Court ("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 Superior Court dismissed the IPP's action, which the IPP's have 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 Supreme Court denied the IPP's request for a stay.

     On March 15, 2001, the IPPs also filed a related complaint before the FERC requesting that the FERC issue an order preventing the Company and the other Vermont utilities from employing FERC Order 888 to require the IPPs, either directly or indirectly, to reserve transmission service and pay transmission charges in connection with their power sales. In principal part the IPPs argue that such reservations and related charges are prohibited under the regulations adopted by the State of Vermont to implement the Public Utilities Regulatory Policies Act of 1978. On April 4, 2001, the Company and the other Vermont utilities filed their response arguing that the IPP complaint should be dismissed on procedural grounds and opposing the IPPs allegations on the merits. By Order dated May 16, 2001, the Commission declined to grant the relief requested and instead found that the complaint was premature in light of the fact that the PSB has yet to rule on the disputed issues in the proceeding open before it to consider the Petition.

     In September 2001, the Petitioners and the IPP's agreed to enter into 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. A similar motion was also filed with the Vermont Supreme Court regarding the appeal on the so-called "scrivener's error" case. On October 18, 2001, the PSB Hearing Officer issued an order granting the Stipulation for Stay and indicated that a status conference will be convened midway through the 90-day period which expires January 4, 2002. An order granting the request for stay is expected from the Vermont Supreme Court.

     At this time, the Company cannot predict the outcome of the proceedings related to Docket No. 6270.

     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 70.1 mW.

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

Production and transmission expenses The decrease in other production and transmission expenses of $1.2 million in the nine months of 2001 resulted primarily from lower generating output and lower power management expenses.

Maintenance expenses The increase in maintenance expenses of $0.3 million in the third quarter of 2001 and $3.3 million for the nine months of 2001 is primarily due to higher service restoration and line maintenance costs.

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Income taxes Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences. For the third quarter and nine months of 2001, these taxes decreased as a result of a decrease in pre-tax earnings and no material change in permanent differences for the period.

Other income and deductions Other income and deductions decreased $6.2 million and $9.8 million for the third quarter and nine months of 2001, respectively. The decrease primarily resulted from the $9.0 million regulatory asset write-off as part of the June 26, 2001 rate order and a third quarter $2.0 million write-down of Eversant's investment in HSS, partially offset by lower equity losses from non-utility subsidiary companies mostly related to Eversant's equity in HSS. Additionally, higher life insurance expenses of $1.2 million were incurred in the third quarter and nine months of 2001. The third quarter of 2000 included $5.4 million non-recurring income related to the successful conclusion of owners' litigation with Northeast Utilities over the Nuclear Regulatory Commission's 1996 shutdown of the Millstone Unit #3 Nuclear Power Plant.

Interest on long-term debt Interest on long-term debt decreased for the third quarter and nine months due to lower debt balances resulting from the maturity of First Mortgage Bonds.

Extraordinary Charge An extraordinary charge of $0.2 million resulted from the application of SFAS No. 71 at Connecticut Valley.

Dividends The increase in preferred stock dividends declared in the third quarter of 2001 is due to a second quarter of 2000 declaration for the third quarter of 2000 dividend.

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. Net cash flow provided by operating activities generated $22.8 million and $48.2 million for the nine months ended September 30, 2001 and 2000, respectively.

     The Company ended the nine months of 2001 with cash and cash equivalents of $49.8 million, an increase of $1.8 million from the beginning of the year. The increase in cash for 2001 was the result of $22.8 million provided by operating activities, offset by $19.0 million used for investing activities and $2.0 million used by financing activities.

     Operating Activities - Net income, depreciation, deferred income taxes and investment tax credits provided cash of $15.2 million. Approximately $7.6 million of cash was provided by working capital and other operating activities. The decrease in cash provided from operating activities for the nine months ended September 30, 2001 compared to September 30, 2000 is due to the Vermont Yankee scheduled refueling outage in 2001, deseasonalized rates which began in July 2000, and the Millstone Unit #3 settlement in August 2000, and other changes in working capital.

     Investing Activities - Construction and plant expenditures used cash of approximately $10.7 million and Conservation and Load Management programs used $0.4 million, while $7.7 million was used for non-utility investments by the Company's subsidiaries and $0.2 million was required for other investing activities.

     Financing Activities - Dividends paid on common stock were $7.6 million, while preferred stock dividends were $0.8 million. Net long-term debt, primarily related to Catamount, provided $6.7 million of capital. In addition, a reduction in capital lease obligations required $0.8 million and the sale of treasury stock and other provided $0.5 million.

     The Company has $16.9 million of letters of credit, which secure three series of Industrial Development Bonds, with expiration dates of May 31, 2002.

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     Current credit ratings of the Company's securities by Standard & Poor's and Fitch, Inc. ("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 July 11, 2001, Fitch removed the Company from its "Rating Watch Negative" status because of the favorable resolution of the Company's rate order with the PSB. Fitch is currently assessing the impact of the rate order on the Company's current credit ratings.

     On July 17, 2001, Standard & Poor's removed the Company from "CreditWatch with negative implications" status in response to the PSB's recent rate order, which stabilized the Company's financial position. Standard & Poor's also affirmed its ratings of the Company, saying that its outlook on the Company is stable.

     Additional information regarding the Company's credit ratings is described in the Company's 2000 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

     Catamount has a revolving credit/term loan facility maturing November 2006 which provides for up to $25 million in revolving credit loans and letters of credit, of which $22.6 million of loans and letters of credit were outstanding at September 30, 2001. This facility has a security interest in Catamount's assets.

     In 1999, SmartEnergy Water Heating Services, Inc., a wholly owned subsidiary of Eversant (formerly SmartEnergy Services, Inc.), secured a $1.5 million, seven-year term loan with Bank of New Hampshire which has an outstanding balance of $1.2 million at September 30, 2001. The interest rate is fixed at 9.50%.

     Financial obligations of the Company's subsidiaries are non-recourse to the Company. On April 25, 2001 the Company sought and in June 2001 the Company received unanimous approval from its First Mortgage Bondholders to enter into a 42nd Supplemental Indenture to the Company's Mortgage dated October 1, 1929 (the "First Mortgage") to exclude its wholly owned non-regulated subsidiary, Catamount Resources Corporation ("CRC") and its subsidiaries (currently Catamount and Eversant), from the term "subsidiary" under the Mortgage. The 42nd Supplemental Indenture (amendment) eliminates the possibility of cross defaults under the First Mortgage occasioned by default on the indebtedness of CRC or its subsidiaries. Additionally, the amendment imposes limitations on the level of the Company's future investment in non-regulated subsidiaries.

     The Company and its subsidiaries' long-term debt arrangements contain financial and non-financial covenants. The Company and its subsidiaries are in compliance with all debt covenants related to its various debt agreements.

Hydro-Quebec Contract

     The Company is purchasing varying amounts of power from Hydro-Quebec under the VJO contract through 2016. Related contracts were negotiated between the Company and Hydro-Quebec which in effect alter the terms and conditions contained in the VJO contract, reducing the overall power requirements and cost of the original contract.

     See Note 6 to the Consolidated Financial Statements for information related to the Hydro-Quebec contract arbitration.

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Diversification

     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 CRC, invests through its wholly owned subsidiaries in non-regulated energy generation projects in North America and Europe. Through its wholly owned subsidiaries, Catamount has interests in ten operating independent power projects located in Glenns Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont; Thetford, England; Hopewell, Virginia; Thuringen, Germany; Mecklenburg-Vorpommern, Germany, Fort Dunlop, England and Summersville, West Virginia. In June 2001, Catamount established Catamount Development GmbH, a German corporate entity, 100% owned by Catamount Heartlands Corp. a wholly owned subsidiary of Catamount. The company was formed to hold Catamount's interests in German "greenfield" development by Catamount or projects, which would be purchased by Catamount in mid to late stage development. Currently, several projects are under development throughout Germany.

     In early 2001, Catamount undertook a comprehensive strategic review and as a result has refocused its efforts from being primarily an investor in renewable energy to a developer, owner, and operator of wind energy projects. As a result of the change in strategic direction, Catamount is pursuing the sale of eight of its non-wind electric generating assets. Proceeds from the sale will be reinvested in the development of new wind projects as well as the acquisition of existing wind projects. Additionally, Catamount is seeking investors and partners to co-invest with Catamount in the acquisition of existing 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.

     In the first quarter of 2001, Catamount reduced its ownership in the Gauley River Power project ("Gauley River") to 50% for the purpose of retaining Qualifying Facility ("QF") status prior to its completion. 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 intent to sell this project and therefore control is considered temporary.

     Gauley River, which was still under construction in the first half of 2001, began commercial operation on July 30, 2001. The project experienced construction delays, which could have resulted in an opportunity for an event of default to be declared under the project's construction loan agreement. A project loan event of default could have, in turn, caused a default under Catamount's $25 million revolving credit agreement. Absent the amendment from the First Mortgage Bondholders described above, a Catamount default under its $25 million credit agreement, if any could have caused a cross default to the Company's First Mortgage Bonds. The First Mortgage amendment ensures that defaults at CRC or any of its majority-owned subsidiaries, including those due to any default at Catamount or Gauley River, would be limited to those subsidiaries and would not affect the Company's First Mortgage Bonds. Gauley River incurred a $0.6 million liquidated damage liability to its primary purchased power contract holder during July 2001, as a result of power production delays.

     Catamount has committed to a $2.1 million letter of credit and up to a $5.0 million security interest in its stock, to secure the payment of potential cost overruns at the Gauley River Power project. Catamount and Gauley River have reached an agreement to settle the construction dispute related to the cost overruns with the contractor, Black & Veatch Construction, Inc. ("Black & Veatch"), subject to lender approval. Under the terms of the agreement, Gauley River Power Partners, LP has agreed to pay Black & Veatch a total of $6.8 million. This amount represents $4.0 million as final settlement on the construction overruns and $1.8 million related to release of retainage upon completion of certain construction items outlined in the agreement. These amounts will be paid in the fourth quarter of 2001. The additional $1.0 million will be paid to the contractor during the first quarter of 2002 and it is expected that the lender will release the security interest in Catamount's stock at that time.

     Catamount's Fibrothetford equity investment has been reduced to zero as a result of losses incurred to date. As of July 1, 2001, losses are being applied to Catamount's note receivable balance. Catamount will also reserve against future interest income on the note receivable, which is expected to be approximately $1.3 million over the next twelve months, due to the uncertainty that it will be collected in the future. Fibrothetford received a deferment of the senior debt principal payment due September 30, 2001, avoiding a potential default. That deferred payment was made at the end of October 2001. Catamount's after-tax earnings were $0.0 million and $0.5 million for the third quarter of 2001 and 2000, respectively, and $0.6 million and $0.8 million for the nine months ended September 30, 2001 and 2000, respectively.

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     Eversant (formerly SmartEnergy Services, Inc.), also a subsidiary of Catamount Resources Corporation, invests in unregulated energy and service related businesses. Overall, Eversant incurred a net loss of $1.3 million and $0.1 million for the third quarter of 2001 and 2000, respectively, and net losses of $1.5 million and $2.4 million for the nine months ended September 30, 2001 and 2000, respectively. Eversant also has an 18.4% ownership interest, on a fully diluted basis, in HSS. HSS establishes a network of affiliate contractors who perform home maintenance repair and improvements via membership. HSS began operations in 1999 and is subject to risks and challenges similar to a company in the early stage of development. HSS launched a Commercial Services division in 2001,which meets the maintenance, repair and installation needs of small businesses, building owners, and property managers. In May 2001, Eversant entered into a convertible loan agreement with HSS and Jupiter Capital. Under the agreement, Eversant loaned HSS $2.0 million and Jupiter Capital 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 Capital in August 2001. Eversant's share of HSS's pre-tax loss for the third quarter of 2001 and 2000 was zero. In September 2001, Eversant recorded a $1.2 million after-tax write-down of its investment in HSS. In addition to the $1.2 million write-down, Eversant previously recorded losses of $9.0 million related to its investment in HSS. As of September 30, 2001, Eversant's net investment in HSS is $1.4 million.

     AgEnergy (formerly SmartEnergy Control Systems), which is a wholly owned subsidiary of Eversant, is currently in arbitration with Westfalia-Surge, the exclusive distributor that markets and sells its SmartDrive Control product. The arbitration concerns the Company's claim that Westfalia-Surge has not conducted itself in accordance with the exclusive distributorship agreement between the parties. The SmartDrive Control product has generated approximately 90% of the sales revenue of AgEnergy. AgEnergy's revenues represent approximately $0.5 million of the total Eversant revenues of approximately $2.5 million, on an annual basis.

Rates and Regulation

     The Company recognizes that adequate and timely rate relief is necessary if the Company 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.

     See Notes 2 and 4 to the Consolidated Financial Statements for information related to Vermont Retail Rates.

Proposed Formation of a Holding Company

     In order to further prepare the Company for deregulation, and to insulate the Company from the risks of its various regulated and unregulated subsidiaries, the Company filed a petition with the PSB in 1998 for permission to create a holding company that would have as subsidiaries the Company and non-utility subsidiaries, Catamount Energy and Eversant Corporation (formerly SmartEnergy Services, Inc.), and their subsidiaries. The proposal had been revised to have Connecticut Valley become a direct subsidiary of the holding company, rather than remain as a subsidiary of the Company. The Company believed that a holding company structure would reduce the Company's Vermont utility's cost of capital and thus would be beneficial to its ratepayers, and would also benefit any future transition to a deregulated electricity market in Vermont. The proposed holding company formation was subject to approval by Federal regulators, including the Securities and Exchange Commission, the FERC, various States and the Company's shareholders. The Company had negotiated an agreement with the DPS regarding code of conduct and affiliate transaction rules to be utilized once a holding company structure is implemented.

     As part of the settlement in the June 26, 2001 rate order, the Company and the DPS agreed to develop and file a schedule for the consideration of the holding company structure for the Company, and to submit an agreement supporting the approval of affiliate transaction rules and codes of conduct for a new holding company. The PSB approved the schedule for the holding company docket, which schedule anticipated a settlement filing, if any, in September and set forth a schedule for litigation, if necessary, beginning in December. The Company and the DPS were unable to reach a resolution of issues, and the Company filed a motion to dismiss its petition. On September 24, 2001, the PSB issued its Order Closing Docket, without prejudice. The Company cannot predict whether it will request PSB approval of a holding company structure in the future.

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ELECTRIC INDUSTRY RESTRUCTURING

     The electric utility industry is in a period of transition that may result in a shift away from rate making 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 Vermont and New Hampshire, where the Company does business, are exploring new mechanisms to bring greater competition, customer choice and market influence to the industry while retaining the public benefits associated with the current regulatory system. Recent events, including those related to restructuring in California and uncertainties concerning the operations of the wholesale markets in New England, have resulted in the slowdown of the restructuring process in Vermont.

Vermont

     Recently, 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 is considering the establishment of policies and procedures to govern retail competition within the Company's service territory. At this time, the Board has concluded its investigation into the restructuring of committed power supply arrangements in Docket No. 6140, the proceeding has been closed and the Company has actively pursued initiatives for such purposes. In addition, the Board is considering whether additional informal consensus building steps should be undertaken in the Docket No. 6330 retail access investigation, or whether, in light of restructuring and market reform uncertainties, the investigation should be closed without prejudice. As a result, the Company cannot determine when or if retail competition will be introduced within the Company's Vermont service territory.

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 filing date for Order No. 2000 was extended to January 16, 2001 for utilities in regions with an existing independent system operator, such as ISO-New England.

     The Company, jointly with GMP, Citizens Utilities and Vermont Electric Power Co. ("VELCO"), 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. The FERC directed an Administrative Law Judge to mediate settlement discussions with the parties for a period of 45 days and file a report within 10 days (due on September 17, 2001).

     During 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. As directed by the FERC, the Administrative Law Judge assigned to the mediation filed a report of the mediation on September 17, 2001.

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

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Competition - Risk Factors

     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 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 Consolidated Financial Statements, the Company believes it currently complies with the provisions of SFAS No. 71 for its regulated Vermont and New Hampshire service territories 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 $34.4 million on a pre-tax basis as of September 30, 2001. In the second quarter of 2001, the Company wrote off $9.0 million ($5.3 million after-tax) of its regulatory assets as part of the July 26, 2001 approved rate order. In the third quarter of 2001, pursuant to the June 26, 2001 approved rate order, the Company applied $2.7 million of the $4.3 million proceeds from the Hydro-Quebec settlement to the balance of the deferred Hydro-Quebec arbitration costs. 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, which agreement is subject to approval by the PSB. 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.

     SFAS No. 121, "Accounting for the Impairment of Long Lived Assets and for Long-Lived Assets to Be Disposed Of," as adopted by the Company on January 1, 1996, requires that any assets, including regulatory assets, that are no longer probable of recovery through future revenues, be revalued based upon future cash flows. SFAS No. 121 requires that a rate-regulated enterprise recognize an impairment loss for the amount of costs excluded from recovery. As of September 30, 2001 based upon the regulatory environment within which the Company currently operates, SFAS No. 121 did not have an impact on the Company's financial position or results of operations. Competitive influences or regulatory developments may impact this status in the future. The Company is currently assessing the impact, if any, of SFAS No. 144, Impairment or Disposal of Long-Lived Assets, which replaces SFAS No. 121 and becomes effective for fiscal years beginning after December 15, 2001.

     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.'s. 71 and 121 will continue to be applicable in the future. In addition, 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 possible that stranded cost exposure before mitigation could exceed the Company's current total common stock equity.

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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.
Items 2, 3, and 4.		None.
Item 5.	None.
Item 6.	Exhibits and Reports on Form 8-K.
	(a)	List of Exhibits.
		10.8.10	2001 Amendatory Agreement dated as of September 21, 2001 to which the Company is a party re: Vermont Yankee Nuclear Power Corporation Power Contract.
	(b)	Item 5.	Other events, dated August 15, 2001 re: Sale of Vermont Yankee Nuclear Power Corporation to Entergy Corporation.
			Dated October 16, 2001 re: Retirement of Francis J. Boyle as Senior Vice President, Chief Financial Officer, and Treasurer.

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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/ John J. Holtman
	John J. Holtman
	Authorized Signatory, Vice President, Principal Accounting Officer, and Controller

Dated November 13, 2001

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