10-Q

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549

Form 10-Q

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

For the quarterly period ended     March 31, 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 April 30, 2001 there were outstanding 11,546,327 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    months ended March 31, 2001 and 2000		3
		Consolidated Balance Sheet as of March 31, 2001 and December 31, 2000		4
		Consolidated Statement of Cash Flows for the three months ended March 31, 2001    and 2000		5
		Notes to Consolidated Financial Statements		6
Item 2.	Management's Discussion and Analysis of Financial Condition and    Results of Operations		14
Item 3.		Quantitative and Qualitative Disclosures about Market Risk		25
PART II.		OTHER INFORMATION		26
SIGNATURE				28

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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
	March 31
	2001	2000
Operating Revenues	$78,032	$99,949
Operating Expenses
Operation
Purchased power	39,449	53,576
Production and transmission	6,637	6,503
Other operation	11,436	10,682
Maintenance	4,626	2,825
Depreciation	4,250	4,283
Other taxes, principally property taxes	3,101	3,025
Taxes on income	2,407	6,491
Total operating expenses	71,906	87,385
Operating Income	6,126	12,564
Other Income and Deductions
Equity in earnings of affiliates	662	746
Allowance for equity funds during construction	17	27
Other income, net	517	(3,064)
(Provision) benefit for income taxes	(167)	1,263
Total other income and deductions, net	1,029	(1,028)
Total Operating and Other Income	7,155	11,536
Interest Expense
Interest on long-term debt	3,209	3,565
Other interest	58	28
Allowance for borrowed funds during construction	(9)	(16)
Total interest expense, net	3,258	3,577
Net Income	3,897	7,959
Retained Earnings at Beginning of Period	78,423	72,371
	82,320	80,330
Cash Dividends Declared
Preferred Stock	424	445
Common Stock	-	-
Total dividends declared	424	445
Other Adjustments	(11)	-
Retained Earnings at End of Period	$81,885	$79,885
Earnings Available For Common Stock	$  3,473	$ 7,514
Average Shares of Common Stock Outstanding	11,530,896	11,466,855
Earnings Per Basic and Diluted Share of Common Stock	$      .30	$     .66
Dividends Paid Per Share of Common Stock	$      .22	$     .22

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)

	March 31	December 31
	2001	2000
Assets
Utility Plant, at original cost	$478,776	$478,324
Less accumulated depreciation	187,992	183,828
	290,784	294,496
Construction work in progress	17,132	15,197
Nuclear fuel, net	1,255	1,283
Net utility plant	309,171	310,976
Investments and Other Assets
Investments in affiliates, at equity	24,526	24,527
Non-utility investments	52,972	46,591
Non-utility property, less accumulated depreciation	2,096	2,172
Total investments and other assets	79,594	73,290
Current Assets
Cash and cash equivalents	52,080	47,986
Special deposits	119	118
Accounts receivable, less allowance for uncollectible accounts             ($1,745 in 2001 and $1,655 in 2000)	23,151	25,006
Unbilled revenues	14,225	17,142
Materials and supplies, at average cost	3,821	3,702
Prepayments	2,026	2,593
Other current assets	5,606	6,511
Total current assets	101,028	103,058
Regulatory Assets	42,915	45,797
Other Deferred Charges	14,724	6,717
Total Assets	$547,432	$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	45,972	45,810
Accumulated other comprehensive income	(906)	(269)
Deferred compensation plans - employee stock ownership plans	(462)	(358)
Treasury stock (240,761 shares, and 277,868, respectively, at cost)	(3,141)	(3,624)
Retained Earnings	81,885	78,423
Total Common Stock Equity	194,063	190,697
Preferred and preference stock	8,054	8,054
Preferred stock with sinking fund requirements	15,000	16,000
Long-term debt	158,795	152,975
Capital lease obligations	13,753	13,978
Total capitalization	389,665	381,704
Current Liabilities
Current portion of long - term debt	5,205	4,205
Accounts payable	4,636	6,407
Accounts payable - affiliates	11,072	13,523
Accrued income taxes	4,032	1,428
Dividends declared	0	2,532
Nuclear decommissioning costs	2,214	2,214
Disallowed purchased power costs	2,934	2,934
Other current liabilities	20,082	23,117
Total current liabilities	50,175	56,360
Deferred Credits
Deferred income taxes	42,460	43,779
Deferred investment tax credits	5,951	6,049
Nuclear decommissioning costs	14,226	14,737
Other deferred credits	44,955	37,209
Total deferred credits	107,592	101,774
Commitments and Contingencies
Total Capitalization and Liabilities	$547,432	$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)

	Three Months Ended                    March 31
	2001	2000
Cash Flows Provided (Used) By:
Operating Activities
Net income	$  3,897	$  7,959
Adjustments to reconcile net income to net cash       provided by operating activities
Equity in earnings of affiliates	(662)	(746)
Dividends received from affiliates	659	1,207
Equity in earnings from non-utility investment	(1,521)	2,668
Distribution of earnings from non-utility investments	673	828
Depreciation	4,250	4,283
Amortization of capital leases	272	272
Deferred income taxes and investment tax credits	(1,071)	(1,916)
Net deferral and amortization of nuclear replacement            energy and maintenance costs	161	1,552
Amortization of conservation and load management costs	1,342	1,305
Decrease in accounts receivable and            unbilled revenues	4,849	17,847
Decrease in accounts payable	(4,003)	(9,994)
Increase in accrued income taxes	2,604	6,907
Change in other working capital items	(1,202)	311
Other, net	(173)	(98)
Net cash provided by operating activities	10,075	32,385
Investing Activities
Construction and plant expenditures	(3,465)	(3,264)
Conservation and load management expenditures	(219)	(405)
Return of capital	47	47
Non-utility investments	(5,611)	(3,508)
Other investments, net	53	20
Net cash used for investing activities	(9,195)	(7,110)
Financing Activities
Sale of treasury stock	484	-
Long-term debt, net	5,820	855
Common and preferred dividends paid	(2,956)	(2,968)
Reduction in capital lease obligations	(272)	(272)
Other	138	-
Net cash provided (used) by financing activities	3,214	(2,385)
Net Increase In Cash and Cash Equivalents	4,094	22,890
Cash and Cash Equivalents at Beginning of Year	47,986	35,461
Cash and Cash Equivalents at End of Year	$52,080	$58,351
Supplemental Cash Flow Information
Cash paid during the year for:
Interest (net of amounts capitalized)	$  3,424	$  3,199
Income taxes (net of refunds)	$    953	$    236

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.

     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: On January 1, 2001, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 133 (subsequently amended by SFAS No.'s 137 and 138), Accounting for Derivative Instruments and Hedging Activities ("FAS 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 purchased power contract that allows the seller to purchase specified amounts of power with advance notice (HQ Sellback #3). This contract has been determined to be a derivative under FAS 133. The fair market value of this derivative is approximately a $7.5 million unrealized loss which has been recorded in Other deferred credits in the accompanying March 31, 2001 Consolidated Balance Sheet. 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 regulatory asset or liability. In the first quarter of 2001, the Company recorded an offsetting regulatory asset for the estimated fair market value of this contract, which is reflected in the accompanying Consolidated Balance Sheet in Other deferred charges.

Note 2 - 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 March 31
	2001	2000
Operating revenues	$ 40,964	$ 40,692
Operating income	$  3,458	$  3,883
Net income	$  1,550	$  1,744
Company's equity in net income	$    485	$    536

Vermont Electric Power Company:

	Three Months Ended March 31
	2001	2000
Operating revenues	$ 7,170	$ 6,715
Operating income	$   740	$   670
Net income	$   243	$   273
Company's equity in net income	$   146	$   142

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Note 3 - 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 Vermont Department of Public Service ("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 has 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 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 is 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 disallows approximately $7.4 million (based on 1999 power costs) for 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. If in the future, the Company is unable to increase rates to recover the temporary disallowed purchased power costs prior to further resolution under the VJO Power Contract or otherwise mitigate these costs; the Company would be required to record losses for any estimated future under recovery.

     These temporary disallowances were calculated using comparable methodology to that used by the PSB in the Green Mountain Power ("GMP") rate case on February 28, 1998. In that case, the PSB found GMP's decision to commit to the VJO Power Contract in 1991 "imprudent" and that power purchased under it was not "used and useful." As a result, the PSB concluded that a portion of GMP's current costs should not be imposed on GMP's customers and were disallowed. GMP appealed that rate order to the Vermont Supreme Court. Should the Company receive a similar order from the PSB, the Company would experience a material adverse effect on its results of operations and financial condition.

     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 1, 2001. The PSB suspended the rate filing and a schedule was set to review the case.

     In January 2001, the PSB issued an order that restored financial stability to GMP through a 3.42% rate increase over and above the two temporary rate increases that were already in effect for that company. GMP was required to

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write off $3.2 million of regulatory assets and the PSB also required GMP to return up to $8.0 million to ratepayers in the event of a merger, acquisition or asset sale, and placed restrictions on GMP's investments in non-regulated operations. In addition, GMP withdrew its Vermont Supreme Court appeal regarding the VJO contracts described above.

     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.

     If the PSB subsequently issues a final rate order adopting the disallowance methodology used to determine the temporary Hydro-Quebec disallowance described above for the duration of the VJO Power Contract, the Company would not be able to recover approximately $179.7 million of power costs over the life of the contract, including $11.3 million in 2001, $11.4 million in 2002, $11.5 million in 2003, $11.7 in million 2004 and $11.8 million in 2005. In such an event, the Company would be required to take an immediate charge to earnings of approximately $179.7 million (pre-tax). Such an outcome could jeopardize the Company's ability to continue as a going concern. However, at this time, the Company does not believe that such a loss is probable particularly in view of the January, 2001 PSB Order issued in GMP's proceedings, the decision of the Vermont Supreme Court reversing and remanding the PSB's preclusion order, and the pending rate case settlement.

     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, 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 take a second-quarter $9.0 million one-time write-off ($5.3 million after-tax) of regulatory assets as part of the settlement, which was filed with the PSB on May 7, 2001. The rate case settlement, which requires PSB approval, provides for new rates effective with bills rendered July 1, 2001. The settlement also provides for a rate freeze through January 1, 2003.

     Deseasonalized Rates: On April 13, 2000, the Company and the DPS filed a stipulated agreement with the PSB to end winter-summer rate differentials for the Company's Vermont customers. 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 have been reduced by 14.9%, while summer rates have been increased by 10.5%. The rate design change will be 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 deferrals, as ordered by the PSB.

New Hampshire Retail Rates: Connecticut Valley Electric Company's ("Connecticut Valley"), 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.

     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 of approximately $1.3 million on a pre-tax basis. This determination was based on various legal and regulatory actions beginning with the February 28, 1997 NHPUC Final Plan to restructure the electric utility industry in New Hampshire and 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 ending with 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 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.

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     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 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. In response, Connecticut Valley offered to place the additional revenues in escrow pending the outcome of the NHPUC's appeal. The Court of Appeals denied the NHPUC's request for a stay so long as the incremental revenues were placed in escrow.

     Pursuant to the March 6, 2000 Court's 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.

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     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, the incremental revenue held in escrow was released and 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.

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 million through 2016. The Company had requested an exit fee of approximately $95 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, 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 $1.5 million (pre-tax) in regulatory assets associated with its wholesale business as of March 31, 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. However, the Company cannot predict the ultimate outcome of this matter.

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

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.

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

     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 ("VT"). The Company received a letter from the State of New Hampshire ("NH") asking the Company to conduct a scoping study in and around the site of the former facility. The Company commissioned an environmental site assessment in late 1999. In April 2000, the Company presented the assessment findings to the states of NH and VT and the town of Brattleboro. The State of VT concluded that additional site monitoring is necessary and the Company submitted a draft Corrective Action Plan that includes a long-term groundwater monitoring program and implements institutional controls at the site to restrict access and exposure. The Company expects to receive State of VT approval of the draft Corrective Action Plan in 2001 and will implement the plan thereafter. The State of NH concluded that additional biological monitoring of the river sediment affected by site wastes is necessary. The State of NH requires this additional work to validate certain

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findings and conclusions made by the Company's consultant after completing its initial investigation in 1999. In 2001, the Company developed and submitted a work plan to the State of NH to address their concerns. The

Company expects state approval so it can complete the work and report on the findings in 2001. 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 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. A mediator on the issue of liability was chosen in April 2001. PSNH submitted a work plan to the State of NH, in December 2000, for further investigation of this site. The Company agreed, with reservations, to participate on a limited basis in the development and completion of that work since the State of NH considers the Company, along with others, as potentially responsible parties at the site. This work requires state review, comment and approval and will occur in 2001. At this time, the Company has not finalized an estimate of 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 March 31, 2001, a reserve of $9.5 million exists and this represents management's best estimate of the costs to remediate the sites discussed above.

Note 5 - Hydro Quebec Power 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.

     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 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 has been and remains 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 from the International Arbitration Tribunal relating to the failure by Hydro-Quebec to deliver power during the outage in 1998. The Tribunal ruled that the long-term power supply contract between Hydro-Quebec and the Vermont utilities remains in effect, although Hydro-Quebec is required to reimburse the Vermont utilities for capacity payments made during the outage. The Tribunal ordered a refund to the VJO of approximately $20 million plus interest, which amount could be adjusted downward to reflect either actual sales in the first quarter of 1998 or an agreement by the parties. The Company would be entitled to up to 45% of such refund. Neither Hydro-Quebec nor the Vermont utilities were awarded legal fees or arbitration costs. The VJO, including the Company, have not determined whether to appeal the Tribunal's decision.

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     In accordance with a PSB Accounting Order, the Company has deferred incremental costs associated with this arbitration of approximately $6.3 million at March 31, 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 May 7, 2001 rate case settlement with the DPS (pending PSB approval), the Company has 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 balances 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. Resolution of the total award related to the Hydro-Quebec arbitration is expected in the second quarter of 2001.

Note 6 - 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 invests in non-regulated, energy-supply projects and SmartEnergy Services Inc. ("SmartEnergy") which pursues retail alliances to market energy and related products and services, engages in the sale of or rental of electric water heaters and has a 26.3% ownership interest in the Home Services Store ("HSS"), on a fully diluted basis. 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 months ended March 31, 2001 and 2000, is as follows (dollars in thousands):

					Reclassification
	CV	CVEC			and Consolidating
	VT	NH	Catamount	SmartEnergy	Other (1)	Entries	Consolidated
2001
Revenues from external customers	$ 72,492	$ 5,541	$    53	$   491	$   -	$  545	$78,032
Intersegment revenues	3,181	-	-	-	-	3,181	-
Net income (loss)	3,596	106	356	(163)	2	-	3,897
Total assets	479,515	12,262	53,981	6,153	316	4,795	547,432
2000
Revenues from external customers	$ 94,938	$ 5,013	$    99	$    887	$    -	$  988	$99,949
Intersegment revenues	3,135	-	-	-	-	3,135	-
Net income (loss)	10,383	109	257	(2,792)	2	-	7,959
Total assets	504,459	12,405	45,964	6,214	393	6,926	562,509

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 pending rate case before the Vermont Public Service Board, the outcome of litigation at the FERC involving the Company's regulated companies, the performance of the Vermont Yankee nuclear power plant weather conditions, and the performance of the Company's unregulated businesses. The Company cannot predict the outcome of any of these matters.

Earnings Overview

     The Company recorded net income of $3.9 million or $.30 per share of common stock for the first quarter of 2001, which equates to a 6.4 % return on average common equity. This compares to net income of $8.0 million or $.66 per share of common stock, and a 5.3 % return on average common equity for the corresponding period last year.

     Lower first quarter 2001 earnings compared to last year resulted primarily from the following factors:

• lower utility revenues of $4.0 million after-tax, or $.34 per share of common stock, primarily resulting from lower average retail revenues in the first quarter of 2001 compared to the same period in 2000 as a result of a Vermont Public Service Board Order which deseasonalized or equalized the Company's winter/summer rates beginning July 1, 2000;

• lower utility revenues of $1.0 million after-tax, or $.09 per share of common stock, primarily resulting from a 2.1% (13,622 mWh) decrease in retail mWh sales;

• higher operating and other costs of $1.6 million after-tax, or $.14 per share of common stock, primarily due to higher service restoration costs related to the severe storm activity in March 2001; and

• lower net losses in the first quarter of 2001 at SmartEnergy Services, Inc. of $2.5 million after-tax, or $.23 per share of common stock.

     Other factors affecting results for the first quarter of 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 March 31
			Percentage			Percentage
	mWh Sales		Increase	Revenues (000's)		Increase
	2001	2000	(Decrease)	2001	2000	(Decrease)
Residential	273,396	277,353	(1.4)	$ 34,370	$38,430	(10.6)
Commercial	232,346	230,600	.8	26,353	28,007	(5.9)
Industrial	114,254	125,642	(9.1)	9,419	11,545	(18.4)
Other retail	1,542	1,565	(1.5)	436	443	(1.6)
Total retail sales	621,538	635,160	(2.1)	70,578	78,425	(10.0)
Resale sales:
Firm	674	663	1.7	38	38	-
Entitlement	53,121	55,590	(4.4)	1,969	1,956	.7
Alliance	0	361,800	(100.0)	0	13,112	(100.0)
Other	81,427	156,909	(48.1)	3,812	4,499	(15.3)
Total resale sales	135,222	574,962	(76.5)	5,819	19,605	(70.3)
Other revenues	-	-	-	1,635	1,919	(14.8)
Total	756,760	1,210,122	(37.5)	$78,032	$99,949	(21.9)

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     Retail mWh sales for the first quarter of 2001 decreased 2.1% compared to the first quarter of 2000, and related revenues decreased $7.8 million, or 10.0% compared to last year. The retail revenue variance is attributable to a $6.4 million price variance primarily due to the impact of deseasonalized rates, implemented in July 2000, and a $1.4 million impact of lower mWh sales primarily from the industrial sector.

     Wholesale mWh sales decreased 76.5%, and revenues decreased 70.3% compared to last year mostly due to the discontinuance of the company's alliance with Virginia Power. 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. Other resale sales decreased 48.1% or 75,482 mWh and revenues decreased $0.7 million or 15.3%. These variances reflect current market conditions in Vermont and New England. These sales, made on a short term basis, include sales to ISO New England and other utilities in New England.

     Other revenues for the first quarter of 2001 are lower than the first quarter of 2000 mainly due to the 1999 provision for rate refund of $.3 million, for Connecticut Valley that was realized in 2000.

Net Purchased Power and Production Fuel Costs The net cost components of purchased power and production fuel costs for the three months ended March 31, 2001 and 2000 are as follows (dollars in thousands):

	2001		2000
	Units	Amount	Units	Amount
Purchased and produced:
Capacity (mW)	439	$ 22,384	460	$ 22,846
Energy (mWh)	742,627	17,065	1,154,295	30,731
Total purchased power costs		39,449		53,577
Production fuel (mWh)   Total purchased power and production fuel costs	70,651	956   40,405	115,999	853 54,430
Less entitlement and other resale sales (mWh)	134,548	5,781	574,299	19,567
Net purchased power and production fuel costs		$ 34,624		$ 34,863

     For the first quarter of 2001, purchased capacity costs decreased $0.5 million compared to 2000, due to discontinued billings from Yankee Atomic for decommissioning costs of which Yankee Atomic had collected sufficient funds from its sponsors in July 2000 and lower nuclear amortization and deferrals related primarily to the Millstone Unit #3 refueling outage in the first quarter of 2001 compared to no refueling outage in 2000, and fewer capacity purchases related to the Company's alliance with Virginia Power. Offsetting these favorable variances, were slightly higher Vermont Yankee capacity costs and increased installed capability ("ICAP") purchases.

     Energy purchases for the first quarter of 2001 decreased $13.7 million primarily related to the discontinuance of the company's alliance with Virginia Power which amounted to energy purchases of $12.7 million. The remaining $1.0 million decrease in energy purchases is primarily due to lower production from the Independent Power Producers and a 2.5% decrease in net power load compared to the first quarter of 2000.

NUCLEAR MATTERS

The Company maintains a 1.7303% joint-ownership interest in Millstone Unit #3 and also owns a 31.3%, 2%, 2%, 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 will receive payment from NU for the incremental energy costs associated with replacement power during the 17 day period that extended 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. Reimbursement of these costs of approximately $0.2 million after-tax is expected in the second quarter of 2001.

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     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, that is expected to last 35 days. 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 1996, Vermont Yankee initiated a Design Basis Documentation project expected to be complete by December 31, 2001. This project was undertaken to incorporate all design documentation into a centralized system. The objective is to ensure that Vermont Yankee maintains its safety margins in connection with any plant modifications. The Design Basis Documentation project will create a set of design basis documents which will support more efficient systematic problem solving, maintenance, and system overview. This effort supports the safe, cost effective, long term operation of the Vermont Yankee plant. Vermont Yankee received FERC approval in 1996 to defer these unrecovered study costs and amortize the costs through billings to Sponsors over the remaining license life of the plant. The Company's 35% share of the total cost for this project is expected to be approximately $7.6 million.

     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 PSB issued its Order Dismissing Petition in Docket No. 6300, the proceeding in which the Company, along with 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 has been retained by Vermont Yankee as the exclusive financial advisor for the auction, planned for this summer. Vermont Yankee expects to announce the results of the auction before the end of 2001. Such results will be subject to regulatory approvals.

     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 DPS, and the 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 contingent on finalization by the parties and FERC approval. The timing of the FERC approval and the financial impact to the Company is not known at this time.

     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 and is now approximately 43% complete. 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 per project plans. 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 has 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 per project plans.

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     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 $11.2 million and $5.2 million, respectively, at March 31, 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.

     As part of the Company's initiative to cut power costs and restructure Vermont's utility industry, 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 is based on unique provisions of the existing contracts and PSB regulations that provide for modifications and alterations that serve the public interest. The petition outlines seven specific elements that, if implemented, would reduce the purchase power costs and reform these contracts for the benefit of consumers.

     On September 3, 1999, the PSB responded to the Company's petition by opening a formal investigation in Docket No. 6270 regarding these contracts. 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. That injunction is now on appeal to the Vermont Supreme Court. The Company, the other moving utilities and the DPS have 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 filing. On November 22, 2000, the IPPs filed dispositive motions in Docket No. 6270 urging the PSB to declare that it lacks jurisdiction to grant relief sought by the Company's Petition. On January 8, 2001, the Company and the other petitioning utilities filed responses to the IPP's motions supporting the Board's exercise of jurisdiction, as called under the Petition. The DPS also made a filing in support of jurisdiction.

     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 have sought summary judgement in this action. Simultaneously, the PSB has asked the Superior Court to dismiss the IPP's action. On November 17, 2000, the Company and the other Vermont municipal utilities participating in this action filed a response to the IPP's request urging the Superior Court to decline to exercise jurisdiction over the scrivener's error matter since doubt exists as to whether the IPP's have raised a justiciable controversy suitable for resolution by the Superior Court. On January 19, 2001, the Superior Court dismissed the IPP's action. By notice dated January 22, 2001, the IPP's appealed the Superior Court's dismissal to the Vermont Supreme Court. The IPPs also asked the 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 their request for a stay. A decision on the appeal to the Supreme Court is expected sometime within calendar year 2001.

     On March 15, 2001, the IPPs also filed a related complaint before the Federal Energy Regulatory Commission ("FERC" or the "Commission") requesting that the Commission 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

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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, CVPS 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. A decision on this complaint is expected from the FERC sometime in the second quarter of 2001.

     At this time, proceedings are continuing in PSB Docket No. 6270. The PSB has not yet established a schedule for final resolution of this matter.

     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.

Other operation expenses The increase in other operation expenses in the first quarter of 2001, of approximately $.8 million resulted primarily from increased medical claims.

Maintenance expenses The increase in maintenance expenses of $1.8 million in the first quarter is primarily due to higher service restoration costs.

Income taxes Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences. For the first quarter 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 increased for the first quarter. The increase primarily resulted from lower equity losses from non-utility subsidiary companies mostly related to SmartEnergy's proportionate share in HSS, offset by an increase in the provision for income taxes.

Interest on long-term debt Interest on long-term debt decreased for the first quarter due to lower debt balances.

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 $10.1 million and $32.4 million for the three months ended March 31, 2001 and 2000, respectively.

     The Company ended the first three months of 2001 with cash and cash equivalents of $52.1 million, an increase of $4.1 million from the beginning of the year. The increase in cash for 2001 was the result of $10.1 million provided by operating activities, offset by $9.2 million used for investing activities and $3.2 million provided by financing activities.

     Operating Activities - Net income and depreciation provided cash of $8.1 million. Approximately $2.0 million of cash was provided by working capital, and other operating activities including the negative impact of deseasonalized rates for the quarter.

     Investing Activities - Construction and plant expenditures used cash of approximately $3.5 million and C&LM programs used $0.2 million, while $5.6 million was used for non-utility investments and $0.1 million was provided by other investing activities.

     Financing Activities - Dividends paid on common stock were $2.5 million, while preferred stock dividends were $0.4 million. Net long-term debt provided $5.8 million of capital and reduction in capital lease obligations required $0.3 million. In addition, sale of treasury stock provided $0.5 million and other financing activities provided $0.1 million.

Page 18 of 28

     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.

     Current credit ratings of the Company's securities by Standard & Poor's and 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. All Standard & Poor's ratings are on "CreditWatch with negative
   implications."
2. All Fitch ratings are placed on "Rating Watch-Down." Fitch, Inc.
   acquired Duff & Phelps Credit Ratings in June 2000.

     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 $21.6 million of loans and letters of credit were outstanding at March 31, 2001. This facility has a security interest in Catamount's assets. Currently, a $1.2 million letter of credit is outstanding to support certain of Catamount's obligations in connection with a debt service requirement in the Appomattox Cogeneration project and aggregated letters of credit of $7.2 million in support of construction and equity commitments for its Gauley River Power project. Catamount has also committed up to a $5.0 million security interest in its stock to secure the payment of cost overruns at the project which is currently behind schedule.

     In 1999, SmartEnergy Water Heating Services, Inc. ("SEWHS"), a wholly owned subsidiary of SmartEnergy Corp. ("SES"), secured a $1.5 million, seven-year term loan with Bank of New Hampshire with an outstanding balance of $1.3 million at March 31, 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 has since received verbal commitments from more than 66 2/3% of its outstanding First Mortgage Bonds (the minimum required) to enter into a 42^nd 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 SES), from the term "subsidiary" under the Mortgage. This amendment eliminates the possibility of cross defaults under the Mortgage occasioned by default on the indebtedness of CRC or its subsidiaries. Gauley River Power Partners, a 50%-owned affiliate of Catamount, which is developing a hydro electric project, has experienced construction delays which 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, in turn, cause a default under Catamount's $25 million revolving credit agreement. Absent this amendment from the First Mortgage Bondholders, a Catamount default under its $25 million credit agreement, if any, could cause a cross default to the Company's First Mortgage Bonds. The First Mortgage amendment will ensure 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. Approval of the 42^nd Supplemental Indenture requires the written consent of 66 2/3% of its outstanding First Mortgage Bonds. Closing on the 42^nd Supplemental Indenture is expected within 30 days.

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

     The Company cannot assure that its business will generate sufficient cash flow from operations or that future borrowing will be available to the Company in an amount sufficient to enable the Company to pay its indebtedness, including the $75.0 million second mortgage bonds, due in 2004, or to fund its other liquidity needs. The Company's ability to repay its indebtedness is, to a certain extent, subject to general economic, financial, competitive, legislative, regulatory, weather and other factors that are beyond its control. The type, timing and terms of future financing that the Company may need will be dependent upon its cash needs, the availability of refinancing sources and the prevailing conditions in the financial markets. The Company cannot guarantee that

Page 19 of 28

financing sources will be available to the Company at any given time or that the terms of such sources will be favorable.

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 5 to the Consolidated Financial Statements for information related to the Hydro-Quebec contract arbitration.

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 Western Europe. Through its wholly owned subsidiaries, Catamount has interests in nine 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 and Fort Dunlop, England. In addition, Catamount has an interest in a project under construction in Summersville, West Virginia. In November 1999, Catamount partnered with CIT Group, a major equipment finance company, and Dana Commercial Credit Corporation, the finance subsidiary of Dana Corporation to form Catamount Investment Company, LLC ("CIC"), which intends to invest in independent power projects in North America and Western Europe. CIC participated in the two German projects mentioned above. Dana Commercial Credit Corporation has subsequently suspended its part in CIC activity.

     Catamount has committed to a $2.1 million letter of credit as well as a $5.0 million security interest in its stock, securing the payment of potential cost overruns at the Gauley River Power project which is currently behind schedule. An arbitration proceeding has begun related to the delay issues, liquidated damages of $1.8 million and cost overruns of $14.0 million involving a Catamount subsidiary, the turbine supplier and the contractor. In January 2001, Catamount reduced its ownership of the project to a non-controlling level. These construction delays could cause a default under Catamount 's $25 million revolving credit agreement. The Company received verbal

commitments from the minimum required of its outstanding First Mortgage Bonds to enter into a 42^nd Supplemental Indenture to the Company's Mortgage to exclude its wholly owned non-regulated subsidiary, CRC, from the term "subsidiary" under the First Mortgage, as discussed above. The Catamount default, if any, could have caused a cross default to the Company's First Mortgage Bonds. Catamount's after-tax earnings were $0.4 million and $0.3 million for the first quarter of 2001 and 2000, respectively.

     SmartEnergy, also a subsidiary of Catamount Resources Corporation, invests in unregulated energy and service related businesses. Overall, SmartEnergy incurred net losses of $0.2 million and $2.8 million for the first quarter of 2001 and 2000, respectively. SmartEnergy also has a 26.3% ownership interest, on a fully diluted basis, in HSS, which is accounted for using the equity method. 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. SmartEnergy's share of HSS's pre-tax loss for the first quarter of 2001 and 2000 was none and $3.7 million respectively. As of March 31, 2001, SmartEnergy's net investment in HSS is $1.3 million.

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 Note 3 to the Consolidated Financial Statements for information related to Vermont Retail Rates.

Page 20 of 28

Proposed Formation of 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, on July 24, 1998, the Company filed a petition with the PSB for permission to create a holding company that would have as subsidiaries the Company and non-utility subsidiaries, Catamount and SmartEnergy. The Company believes that a holding company structure will reduce the Company's Vermont utility's cost of capital and thus will be beneficial to its ratepayers. It will also benefit any future transition to a deregulated electricity market in Vermont. The proposed holding company formation must also be approved by Federal regulators, including the Securities and Exchange Commission, the FERC, various States and by the Company's shareholders. The Company has negotiated an agreement with the DPS regarding code of conduct and affiliate transaction rules to be utilized once a holding company structure is implemented. The Company has informed the PSB that it is prepared to present the Code of Conduct and affiliate transaction rules to the PSB for it's review and approval, while the DPS had informed the PSB that it prefers to defer the PSB's review until other regulatory issues are resolved.

     On May 7, 2001, the Company and the DPS agreed to develop a schedule for the consideration of a 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 within 30 days of a PSB decision in the pending rate case. The parties agreed to develop a schedule on holding company docket issues by July 1, 2001.

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 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 restructuring proposals; 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.

The Working Group

     On July 22, 1998, the Governor of Vermont issued an Executive Order establishing the Working Group on Vermont's Electricity Future to lead a new effort to review the issues of potential restructuring of Vermont's electric industry. The Working Group was created to determine how restructuring the electric industry in Vermont could reduce both current and long-term electric costs for all classes of Vermont electric consumers. The Working Group was asked to provide a fact-based analysis of the options for electric industry restructuring and the impact of such industry changes on consumers and upon Vermont utilities. Further, the Working Group was directed by the Governor to gather information on and evaluate the possible consequences of the current financial status of Vermont electric utilities.

     A report was issued by the Working Group on December 18, 1998. Key conclusions of the report were:

• The bankruptcy of Vermont electric utilities should not be viewed as an appropriate means to reduce Vermont utilities' committed power supply costs.

• Vermont should restructure its electric industry by moving rapidly to retail choice whereby consumers would purchase power directly from competing power suppliers.

• Vermont electric utilities should pursue power contract renegotiations through payments to buy down power contracts or buy-out power contracts. Financing for such payments should be obtained in the capital markets after a comprehensive regulatory process dealing with all of the elements of the restructuring of the Vermont electric utility industry.

Page 21 of 28

• The Vermont electric utilities should pursue auctions of their power generation assets and remaining power contracts.

• Consolidation of existing electric utilities in Vermont (there are currently 22 utilities) should be considered in order to effect additional savings for utility customers.

     The Working Group noted that by March 1, 2000, most New Englanders outside Vermont would have a choice of their power supplier. While New England has some of the highest electricity rates in the nation, electricity costs in Vermont have been among the lowest in the region, although the Company's rates are higher than the Vermont average. However, that advantage is eroding as other states in New England restructure their electric utility industries. Therefore, the Working Group noted that it is in the interest of Vermont ratepayers to have the benefit of a restructured electric utility industry as soon as possible.

Public Service Board Docket No. 6140

     On September 15, 1998, the PSB opened Docket No. 6140 with the goal of creating a regulatory environment and a procedural framework to call forth, for disciplined review, proposals for reducing current and future power costs in Vermont. The PSB intended that this proceeding define one or more acceptable courses for power supply reform. All Vermont utilities were made a party to the proceeding. Subsequent to the PSB's announcement, preliminary position papers were filed and a series of technical conferences were convened with the PSB to recommend the scope of the investigation, potential courses for reform of Vermont's power supply and other matters associated therewith including the consideration of the Working Group's recommendations.

     On March 3, 1999, the Company filed its Restructuring Plan, a Working Plan to restructure a significant portion of Vermont's Electric Utility Industry, with the PSB and parties in Docket No. 6140. The Company's plan was a joint plan with GMP. On July 12, 1999, the PSB issued a Status Order concluding that the objective of implementing power supply reform may be advanced more effectively in ways other than holding further technical conferences in the docket. Absent good reason to hold one or more technical conferences pertinent to power supply reform, the PSB indicated that the docket would be closed on December 31, 1999, which action has occurred. As a companion proceeding to its Docket No. 6140 investigation, on January 19, 1999, the PSB issued an order opening a new contested case proceeding, Docket No. 6140-A, where it indicated that it intended to issue final, binding and appealable orders concerning matters related to the reform and restructuring of Vermont's electric utility industry. Initially, the PSB notified parties that it intended proceedings in Docket No. 6140-A to consider matters associated with the bankruptcy of one or more of the Vermont electric utilities. After an opportunity for comment, the focus of the proceeding was amended to consider the principles, authority and proposals for reform of Vermont's electric power supply. This included issues associated with the scope and extent of the PSB's authority to approve "securitization" and other financing proposed to be entered into in connection with the buy-out or buy-down of power contracts and the criteria to be applied by the PSB when considering voluntary utility restructuring proposals.

     By Order dated June 24, 1999 in Docket 6140-A, the PSB formally adopted the Vermont Principles on Electric Utility Restructuring. The Order explains that proposals to open utility franchise service areas to retail competition, including the company's Restructuring Plan, will only be approved if they can be found to satisfy the public good after due consideration is given to each of 14 Restructuring Principles. If one or more of the principles is not satisfied by the proposal, then the proponent must offer justification for the deficiency and demonstrate satisfaction of certain statutory requirements. As such, the PSB stated that any filing proposing to open a franchise territory to retail choice would have to be supported, at a minimum, by an explanation of how that proposal fulfills the policy objectives established by the Vermont Principles on Electric Utility Restructuring.

     With regard to financing, no party to the investigation asked that the PSB clarify its authority or issue a declaratory ruling concerning the criteria to be considered when approving utility financing for the buy-out or buy-down of committed power contracts. During the investigation, both the Company and GMP asserted that anticipated refinancing approaches could be accomplished utilizing the existing Vermont and federal legislative regime that governs the regulation of electric utilities and that "securitization" style financing were not presently being contemplated. Because no party to the Docket contradicted these statements, the PSB accepted our assertions and took no further action to evaluate specific utility financing proposals.

     In contrast, Vermont Electric Power Producers, Inc. ("VEPP"), purchasing agent for the purchase of power from qualifying facilities pursuant to PSB Rule 4.100, proposed to use administrative securitization to finance the reform of its power purchase contracts. However, at the request of all commenting parties, the PSB determined to withhold

Page 22 of 28

judgment on the issue as to whether the PSB had jurisdiction to authorize a VEPP financing until such time as a specific proposal was actually filed with the PSB. In the absence of any requests for further investigation or action to be filed within 30 days of the Docket No. 6140-A Order, the PSB indicated that this investigation would be closed, which action has occurred. To follow up on its proposal, on June 15, 2000, VEPP filed a petition requesting that the PSB issue a declaratory ruling confirming the authority of the PSB to issue voluntary administrative securitization orders relative to those qualifying facilities currently holding purchase power contract under PSB Rule 4.100. By order dated June 30, 2000 the PSB opened Docket No. 6396. As part of the Docket proceedings, the PSB convened a workshop to hear detailed presentations on the VEPP proposal. Parties to the Docket filed their positions on the Board's authority to issues related to the requested ruling in mid-November. On January 10, 2001, the PSB convened an oral argument on the VEPP financing proposal. On March 28, 2001, the PSB issued an order in which it concluded that, under current law, it did not have the authority to issue an administrative securitization order in the form requested. The order indicated that the PSB's analysis was intended simply to provide guidance, and did not constitute a final, binding, appealable order. The order also recommended that the Vermont Legislature consider proposals that would clearly enable the PSB to issue the type of securitization order suggested by VEPP and that given the pressing need to mitigate power purchase costs, a mechanism such as that proposed by VEPP could be a very valuable "tool to have in the toolbox" of financial instruments for Vermont.

     The Company supports the Working Group recommendations described above and believes that the restructuring of the electric industry is essential to improve its financial position, enhance its ability to effectively compete in a changing electric utility industry and stabilize projected costs.

     As a result, the Company has pursued a comprehensive financial Restructuring Plan, certain elements of which were included in the Plan that the Company and GMP filed with the PSB in the first quarter of 1999 in connection with the proceedings in Docket No. 6140 described above. The Company is aggressively pursuing implementation of the Restructuring Plan which includes the following elements:

• Retail choice: voluntarily giving up the exclusive right to supply power to the Company's present electric customers, while retaining its rights as a distribution company, as part of a global settlement of regulatory issues.

• Renegotiation of certain purchased power contracts: reducing the Company's future cost of power by renegotiating power contracts, specifically those with Hydro-Quebec and the Vermont purchasing agent's contracts with IPPs which together represent approximately 40% of the Company's 1998 net energy supply. The Company may seek to finance the cost of any buy-outs or buy-downs of power contracts through the future issuance of securities in the capital markets.

• Contract and asset disposition: seeking to sell power purchase contracts and generating assets, including the Company's interest in the Vermont Yankee nuclear generating plant. For an update on the Vermont Yankee sale, see Nuclear Matters described above.

• Cost-cutting: implementing cost-cutting measures to reduce cash flow requirements while maintaining safety and reliability standards.

• Holding company: establishing a holding company in order to further prepare the Company for deregulation.

• Industry consolidation: evaluating possible consolidations with other Vermont electric distribution companies.

• Regulatory settlement: seeking a comprehensive regulatory settlement that leads to long-term financial stability.

• Energy efficiency activities: creating a state sponsored "energy-efficiency utility" to take over most system-wide energy-efficiency services for electric customers. On September 30, 1999, the PSB issued a final order approving a Memorandum of Understanding between the Company, the DPS, all other Vermont electric utility companies and other interested parties that calls for the establishment of the energy-efficiency utility and provides for its funding via a separate stated Energy Efficiency Charge. As of March 2000, system-wide energy-efficiency services are provided to the Company's customers by Efficiency Vermont, the contractor selected by the PSB to serve as the energy-efficiency utility.

Page 23 of 28

Public Service Board Docket No. 6330

     On November 23, 1999, the Company and GMP (together the "Companies") filed a joint Petition and Supporting Materials with the PSB asking that the PSB open an investigation to establish retail access policies and procedures to resolve issues that must be decided to implement the Companies' Restructuring Plan. Specifically, the Petition requests that the PSB issue such orders and approvals as are necessary or advisable to:

1. permit the Companies to suspend their provision of power supply services ("Generation Service") to customers located within their respective service territories;
2. permit the Companies to amend their service tariff obligations to clarify that they retain their exclusive service franchises as providers of electric delivery services ("Delivery Service") to customers within their respective service territories;
3. permit the Companies to implement a Retail Open Access Tariff ("ROAT") that enables customers located within the Companies' respective service territories to choose their power supplier from an array of approved energy service providers ("ESP"), and to purchase Generation Service from such ESPs at market-determined prices;
4. select through a competitive bidding process an ESP or ESPs to deliver "Default Service" for energy to customers located within the Companies' service territories; that do not otherwise have an arrangement with an ESP for the provision of Generation Service;
5. select through a competitive bidding process an ESP or ESPs to deliver "Transition Service" for energy to customers located within the Companies service territories; and
6. approve revisions and modifications to the Companies' tariffs to implement voluntary retail access within the Companies' respective service territories as provided for pursuant to this Petition.

     The consent to retail access within the Companies' service areas established by the Petition is voluntary and conditional. Pursuant to the Petition, the Companies' consent to customer choice and retail competition is expressly conditioned upon approval of all elements of the Companies' Restructuring Plan including the approval of any proposed mitigation measures to reduce power costs and financing measures related thereto, and a mechanism to recover the costs rendered stranded on account of the move to retail access and customer choice.

     On January 14, 2000, the PSB opened Docket No. 6330 to consider the issues raised by the Companies' petition. In its opening Order, the Board states:

"The scope of this investigation is intended to address many of the more detailed aspects of retail open access. While current law may not permit this Board to require retail open access of Vermont utilities, the companies are clearly able to open their service territories on a voluntary basis. Whether retail open access is established on a voluntary basis through existing statutes or through revised legislation, there are many technical issues to be resolved. This investigation will serve to advance many aspects of issues surrounding retail open access."

     An initial pre-hearing conference was held in this investigation on January 31, 2000. The parties to Docket No. 6330 have agreed to consider the Companies proposal in a proceeding consisting of two phases. In Phase I parties will identify the scope and extent of consensus on docket issues (Module 1) and attempt to negotiate agreements on matters where consensus does not initially emerge (Module 2). In Phase II, parties will litigate unresolved issues. As part of the Phase I, Module 1, activities, the PSB convened an extensive two-day education conference in October 2000 to hear presentations on the lessons learned in other jurisdictions and to fill information voids identified by Docket participants during approximately 25 education working group sessions held in the proceeding during much of calendar year 2000. Also in April 2001, the PSB convened a daylong roundtable to consider issues concerning the competitiveness of the New England regional power market. At this time, it is premature to predict the date upon which a final PSB resolution of the matters raised in this investigation will be decided. Note that the Companies proposed an initial start date for retail competition when all of the elements of the joint Restructuring Plan are completed.

     The move to customer choice is likely to be delayed in Vermont, given developments in California and in New England related to restructuring.

Page 24 of 28

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. Statement of Accounting Standards, 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 both its regulated Vermont service territory and FERC regulated wholesale businesses. In the event the Company determines that it no longer meets the criteria for following SFAS No. 71, the accounting impact would be an extraordinary, non-cash charge to operations of approximately $42.9 million on a pre-tax basis as of March 31, 2001. As previously discussed in the Vermont Retail Rate Proceedings, the Company has agreed to take a second-quarter $9.0 million one-time write-off ($5.3 million after-tax) as part of the rate case settlement, which was filed with the PSB on May 7, 2001. 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," which 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 March 31, 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.

     Because the Company is unable to predict what form possible future restructuring legislation will take, it cannot predict if or to what extent SFAS Nos. 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.

Page 25 of 28

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 and 3.
None.
Item 4.	Submission of Matters to a Vote of Security Holders.
	(a)	The Registrant held its Annual Meeting of Stockholders on May 1, 2001.
	(b)	Directors elected whose term will expire in year 2004:
					Votes FOR	Votes WITHHELD
			William V. Boettcher		9,724,401	158,386
			Timothy S. Cobb		9,746,760	136,027
			Luther F. Hackett		9,738,906	143,881
			Janice L. Scites		9,746,018	136,769
		Directors elected whose term will expire in year 2002:
					Votes FOR	Votes WITHHELD
			George MacKenzie, Jr.		9,727,943	154,844
		Other Directors whose terms will expire in 2002:
			Rhonda L. Brooks
			Robert H. Young
			Herbert H. Tate
		Other Directors whose terms will expire in 2003:
			Robert L. Barnett
			Frederic H. Bertrand
			Robert G. Clarke
			Mary Alice McKenzie
Item 5.
None.
Item 6.	Exhibits and Reports on Form 8-K.
	(a)	List of Exhibits
		A 10.93		Management Incentive Plan for Executive Officers dated January 1, 2001.
		A 10.94		Termination Agreement dated January 23, 2001 entered into between Central Vermont Public Service Corporation and Craig A. Parenzan.
				A - Compensation related plan, contract or arrangement
Page 26 of 28
	(b)	Item 5.		Other events, dated February 9, 2001 re: Supreme Court Retail Rate Case Proceeding relating to Hydro-Quebec and filing of Rate Case.
				Dated February 14, 2001 re: Vermont Public Service Board Order dismissing Petition for sale of Vermont Yankee.
				Dated April 17, 2001 re: Hydro-Quebec Arbitration, FERC Stranded Cost Proceeding and 42nd Supplemental Indenture.
				Dated May 7, 2001 re: Settlement Agreement on Rate Case and Hydro-Quebec issues between Vermont Department of Public Service and the Company.

Page 27 of 28

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/ Francis J. Boyle

                                                                       Francis J. Boyle, Senior Vice President, Principal

                                                                                        Financial Officer and Treasurer

                                            By                                                /s/ John J. Holtman

                                                                       John J. Holtman, Vice President and Controller,

                                                                                       Principal Accounting Officer

Dated May 11, 2001

Page 28 of 28

EX-10

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
MANAGEMENT INCENTIVE PLAN

Effective as of January 1, 2001

TABLE OF CONTENTS

ARTICLE I	INTRODUCTION AND PURPOSE		Page
	1.1	Purpose of the Plan	1
ARTICLE II	DEFINITIONS
	2.1 2.2 2.3 2.4 2.5	"Annual Incentive Award" "Award Payment Date" "Board" or "Board of Directors" "Change in Control" "Code"	2 2 2 2 2
	2.6 2.7 2.8 2.9 2.10	"Committee" "Company" "Compensation" "Effective Date" "Eligible Employee"	2 2 2 2 3
	2.11 2.12 2.13 2.14 2.15	"For Cause" "Group 1 Eligible Employee" "Group 2 Eligible Employee" "Participant" "Performance Goals"	3 3 3 3 3
	2.16 2.17 2.18	"Performance Period" "Permanent and Total Disability" "Plan"	3 3 3
ARTICLE III	PARTICIPATION
	3.1	Participation	4
ARTICLE IV	PERFORMANCE GOALS AND AWARD OPPORTUNITIES
	4.1 4.2 4.3 4.4	Performance Goals Performance Levels Participation Goals Amount of Award	5 5 6 6
ARTICLE V	DETERMINATION AND PAYMENT OF ANNUAL INCENTIVE AWARDS
	5.1 5.2 5.3 5.4 5.5	Timing and Determination of Annual Incentive Awards Short Performance Year Termination, Death, Retirement or Permanent and Total Disability Change in Control Limitation on Right to Payment of Award	8 8 9 9 9
ARTICLE VI	ADMINISTRATION
	6.1 6.2 6.3	Committee Authority of the Committee Costs	10 10 10
ARTICLE VII	MISCELLANEOUS
	7.1 7.2 7.3 7.4 7.5 7.6 7.7 7.8 7.9 7.10 7.11 7.12 7.13 7.14	Amendment Termination Employment Rights Nonalienation of Benefits No Funding Tax Withholding Controlling Laws Gender and Number Action by the Company Mistake of Fact Severability Effect of Headings No Liability Successors	11 11 11 12 12 12 12 12 12 12 12 13 13 13

ARTICLE I INTRODUCTION AND PURPOSE

1.1

Purpose of the Plan. The Central Vermont Public Service Corporation Management Incentive Plan (the "Plan") is an incentive compensation program for eligible officers of Central Vermont Public Service Corporation (the "Company"). The purpose of the Plan is to focus the efforts of the Executive Team in achievement of challenging and demanding objectives. The Plan is designed and intended to further the attainment of the customer service, financial, process improvement and employee related objectives of the Company, to assist the Company in attracting and retaining highly qualified executives, and to enhance the mutual interest of customers, shareholders and eligible officers of the Company. In addition, this Plan supports the Company's performance oriented culture.

ARTICLE II DEFINITIONS
2.1	"Annual Incentive Award" shall mean a cash incentive payable to a Participant under the terms of this Plan.
2.2	"Award Payment Date" shall mean, for each Performance Period, the date that the amount of the Annual Incentive Award for that Performance Period shall be paid to the Participant under Article 5 of the Plan.
2.3	"Board" or "Board of Directors" shall mean the Board of Directors of the Company.
2.4	"Change in Control" is fully defined in the Change of Control Agreement, page 2, Section 3 Change of Control.
2.5	"Code" shall mean the Internal Revenue Code of 1986, as amended, and references to particular provisions of the Code shall include any amendments thereto or successor provisions and any rules and regulations promulgated thereunder.
2.6	"Committee" shall mean the Compensation Committee of the Board of Directors of the Company or any other duly established committee or subcommittee appointed by the Board for purposes of this Plan.
2.7	"Company" shall mean Central Vermont Public Service Corporation, a Vermont corporation.
2.8	"Compensation" shall mean a Participant's base pay for the Performance Period for which the amount of an Annual Incentive Award is being determined.
2.9	"Effective Date" shall mean January 1, 2001. The Plan shall be effective for the Performance Period beginning on January 1, 2001.
2.10	"Eligible Employee" shall mean an Employee who is a Group 1 Eligible Employee or a Group 2 Eligible Employee. An Eligible Employee may not be both a Group 1 Eligible Employee and a Group 2 Eligible Employee.
2.11	"For Cause" shall mean, but is not limited to, fraud, dishonesty, theft of corporate assets, gross misconduct, failure to substantially perform assigned duties, material breach of any agreement with the Company, the commission of a crime or act which involves dishonesty or moral turpitude, or willful misconduct which subjects the Company to potential liability.
2.12	"Group 1 Eligible Employee" shall mean the Chief Executive Officer (CEO) of Central Vermont Public Service Corporation and other executive officers of the regulated part of the Company.
2.13	"Group 2 Eligible Employee" shall mean (1) the President and Chief Operating Officer (COO) and other executive officers of Catamount Energy Corporation (Catamount); and (2) the Vice President of Business Development and other executive officers of Smart Energy Services (SES).
2.14	"Participant" for a Performance Period shall mean each Eligible Employee who is an Eligible Employee for that Performance Period.
2.15	"Performance Goals" shall mean the measures of the Company's performance as defined in Section 4.1 of this Plan that must be met for any Participant to receive any Annual Incentive Award under this Plan, as provided in Section 4.1.
2.16	"Performance Period" shall mean the taxable year of the Company or any other period designated by the Committee with respect to which an Annual Incentive Award may be granted.
2.17	"Permanent and Total Disability" shall mean any disability that would qualify as permanent and total disability under any long term disability policy sponsored by the Company.
2.18	"Plan" shall mean this Central Vermont Public Service Corporation Management Incentive Plan, as it may be amended from time to time.

ARTICLE III PARTICIPATION

3.1

Participation. An Eligible Employee will become a Participant in this Plan as of the later of the Effective Date, the Eligible Employee's date of hire or the date the individual becomes an Eligible Employee. An Eligible Employee who is a Participant for the entire length of a Performance Period shall be eligible for consideration for an Annual Incentive Award with respect to that Performance Period. The Committee may provide a prorated Annual Incentive Award for an Eligible Employee who becomes a Participant during the Performance Period.

ARTICLE IV PERFORMANCE GOALS AND AWARD OPPORTUNITIES
4.1	Performance Goals. The measures of Performance Goals are established as follows: Corporate Performance. A measure of overall corporate financial performance based upon cash flow from operating activities. Strategic Business Unit Performance. Measures the performance of each Strategic Business Unit (SBU) or of overall corporate performance, depending on the officer's responsibilities. These performance measures which are established annually are a balanced set of measures including customer satisfaction, financial performance, process improvement and employee measures. Individual Performance. Based on advice and recommendation from the Chief Executive Officer for those reporting to him. The Chairman and Committee evaluate the Chief Executive Officer's performance. SBU and Individual Performance Goals will be established in writing for each Performance Period by no later than the first quarter of the Performance Period. For all of Central Vermont Public Service Corporation's Executive Officers (e.g. Group 1 Eligible Employees), SBU performance is given a 50% weight with the other two measures equally weighted at 25%. For the executives in the unregulated businesses of Catamount and SES (e.g. Group 2 Eligible Employees), the SBU Performance is given an 80% weight with the other two measures equally weighted at 10%.
4.2	Performance Levels. Corporate and SBU measures described in Section 4.1 will be established for three performance levels: threshold, target and maximum. These levels are set based on the following probabilities: 90% probability of achieving the threshold level; 50% probability of achieving target level; and 10% probability of achieving the maximum level.
4.3	Participant Goals. Participants will have a combination of Corporate Performance, SBU Performance and Individual Performance measured goals used in determining any Annual Incentive Award as described in 4.1 above.
4.4	Amount of Award. Following the completion of the Performance Period, the Committee shall undertake or direct a calculation of actual performance for each of the Corporate and SBU measures for such performance year, based on criteria used in the measures. The actual award opportunity for each Participant will be determined as follows; Linear interpolation between three points where achieving the threshold level of performance results in no payout; the target level of performance results in 100% of the target payout and achieving the maximum level of performance results in a 200% of the target payout. A weighted average of the target incentive multiplier for each component of the Corporate measure will be determined. (For the year 2000 there is only one Corporate measure). A weighted average of the target incentive multiplier for each component of the applicable SBU measure will be determined. A weighted average of the target incentive multiplier for each component of the Individual Performance measure will be determined. A weighted average of the target incentive multiplier for the Corporate, SBU and Individual Performance measures will be determined, based on the weightings described in Section 4.1 for Group 1 Eligible Employees and Group 2 Eligible Employees. The final target incentive multiplier will be multiplied by the Participant's target incentive percentage to determine the Annual Incentive Award percentage. The Annual Incentive Award percentage will then be multiplied by the Participant's Compensation to determine the Participant's Annual Incentive Award, prior to any further reductions as described in this Plan, including Sections 5.2, 5.3, 5.4, 5.5 and 6.2.

ARTICLE V DETERMINATION AND PAYMENT OF ANNUAL INCENTIVE AWARDS
5.1	Timing and Determination of Annual Incentive Awards. Following the completion of a Performance Period, the Committee shall undertake or direct an evaluation of performance results as compared to the appropriate performance criteria established for the Performance Period as determined in Article IV. The Committee will report to the Board with respect to achievement of previously approved Corporate, SBU and Individual Performance targets for that Performance Period, and will submit to the Board its recommendations as to the appropriate award payment levels for each eligible participant. Recommendations of the Committee, with such modifications as may be made by the Board, will be biding on all Participants. No Annual Incentive Award may be paid without the prior approval of the Committee. Any Annual Incentive Awards will be paid on the Award Payment Date, which shall be as soon as practicable following the end of the Performance Period to which they relate.
5.2	Short Performance Year. In the event that a determination of an Annual Incentive Award must be made for a Performance Period of less than 12 months, and the year of termination of employment, the determination shall be made in accordance with the provisions of this Plan, except that: In the year of hire, if hired after the first date a Performance Period begins, or year of termination, retirement, death, or Permanent and Total Disability, the amount otherwise determined under the Plan shall be prorated to reflect the period of time during which the Participant was a Participant in the Plan compared to the total period of time of the Performance Period. In the year of a Change in Control, the Company will be assumed to have achieved a target performance level prorated by time.
5.3	Termination, Death, Retirement or Permanent and Total Disability. In the event of the termination, death, retirement, or Permanent and Total Disability of a Participant during a Performance Period, such Participant may, only in the discretion of the Committee, be eligible for a prorated Annual Incentive Award with respect to that Performance Period to the extent the Committee deems appropriate.
5.4	Change in Control. Notwithstanding any of the Plan provisions to the contrary, if a Change in Control occurs during a Performance Period, each Participant will, effective as of the date of the Change in Control, become fully vested in his right to receive an Annual Incentive Award based on the Plan's provisions for such Performance Period in which the Change in Control occurs.
5.5	Limitation on Right to Payment of Award. Notwithstanding any other Plan provision to the contrary, no Participant shall have a right to receive payment of an Annual Incentive Award under the Plan if, subsequent to the commencement of the Performance Period and prior to the date any award would otherwise be payable, is terminated For Cause.

ARTICLE VI ADMINISTRATION
6.1	Committee. The Plan shall be operated and administered by the Committee.
6.2	Authority of the Committee. The Committee shall have full power except as limited by law, the bylaws of the Company or any restrictions or directions imposed by the Board and subject to the provisions herein, to determine the Performance Goals during each Performance Period, to determine the terms, conditions and amounts of Annual Incentive Awards in a manner consistent with the Plan, and to establish, amend or waive rules and regulations as it deems appropriate for the Plan's administration in a manner consistent with the terms of this Plan. Further, the Committee shall make all other determinations that may be necessary or advisable for the administration of the Plan. The Committee's determinations and interpretations with respect to this Plan shall be binding on all parties. While the Committee may appoint individuals to act on its behalf in the administration of this Plan, the Committee will have the sole, final and conclusive authority to administer, construe and interpret this Plan. The Committee may, for reasons it deems appropriate, in its discretion, determine to delay, disapprove, reduce or eliminate any Participant's Annual Incentive Award as it deems warranted by extraordinary circumstances.
6.3	Costs. The Company shall pay all costs of administration of the Plan.

ARTICLE VII MISCELLANEOUS
7.1	Amendment. The Committee or the Board may at any time alter or amend any provision of the Plan, provided that no such amendment that would require the consent of the stockholders of the Company pursuant to the Code, or any other applicable law, rule or regulation, shall be effective without such consent. No such amendment which adversely affects in any material way a Participant's rights to, or interest in, an Annual Incentive Award earned through the end of the Performance Period in which such amendment is adopted or becomes effective unless the Participant shall have agreed thereto in writing, unless such amendment is required by applicable law.
7.2	Termination. The Committee or Board may suspend or terminate this Plan at any time, and in the case of such termination, the following provisions of this Section shall apply notwithstanding any other provisions of the Plan to the contrary. In no event shall the suspension or termination of the Plan adversely affect the rights of any Participant to an Annual Incentive Award earned through the end of the Performance Period in which such suspension or termination is adopted or becomes effective, unless the Participant shall have agreed thereto in writing.
7.3	Employment Rights. The Plan does not constitute a contract of employment and participation in this Plan will not give an Eligible Employee the right to be rehired or retained in the employ of the Company, nor will participation in this Plan give any Eligible Employee any right or claim to any benefit under this Plan, unless such right or claim has specifically accrued under the terms of this Plan. This Plan is not a contract between the Company and its Eligible Employees or Participants. No Participant or other person shall have any claim or right to be granted an Annual Incentive Award under this Plan until such Annual Incentive Award is actually granted. Neither the establishment of this Plan, nor any action taken hereunder, shall be construed as giving any Participant any right to be retained in the employ of the Company. Nothing contained in this Plan shall limit the ability of the Company to make payments or awards to Participants under any other plan, agreement or arrangement. To the extent any provision of this Plan conflicts with any provision of a written agreement between an Employee and the Company, the provisions of the employment agreement shall control.
7.4	Nonalienation of Benefits. A Participant's right and interest under the Plan may not be assigned or transferred and any attempted assignment or transfer shall be null and void and shall extinguish, in the Company's sole discretion, the Company's obligation under the plan to pay Annual Incentive Awards with respect to the Participant.
7.5	No Funding. The Plan shall be unfunded. The Company shall not be required to establish any special segregation of assets to assure payment of Annual Incentive Awards.
7.6	Tax Withholding. The Company shall have the right to deduct from Annual Incentive Awards paid any taxes or other amounts required by law to be withheld.
7.7	Controlling Laws. All questions pertaining to the construction, regulation, validity and effect of the provisions of the plan shall be determined in accordance with the laws of the State of Vermont, except to the extent superseded by laws of the United States.
7.8	Gender and Number. Where the context admits, words in the masculine gender shall include the feminine gender, the plural shall include the singular and the singular shall include the plural.
7.9	Action by the Company. Any action required of or permitted by the Company under this Plan shall be by written resolution of the Board or by a person or persons authorized by written resolution of the Board.
7.10	Mistake of Fact. Any mistake of fact or misstatement of fact shall be corrected when it becomes known and proper adjustment made by reason thereof.
7.11	Severability. In the event any provision of this Plan shall be held to be illegal or invalid for any reason, such illegality or invalidity shall not affect the remaining parts of this Plan, and this Plan shall be construed and endorsed as if such illegal or invalid provision had never been contained in this Plan.
7.12	Effect of Headings. The descriptive headings of the Articles and Sections of this Plan are inserted for convenience of reference and identification only and do not constitute a part of this Plan for purposes of interpretation.
7.13	No Liability. No member of the Board or the Committee or any officer or employee of the Company or an affiliate shall be personally liable for any action, omission or determination made in good faith in connection with this Plan. The Company shall indemnify and hold harmless the members of the Committee, the Board and the officers and employees of the Company and any affiliates, and each of them, from and against any and all loss which results from liability to which any of them may be subjected by reason of any act or conduct (except willful misconduct or gross negligence) in their official capacities in connection with the administration of this Plan, including all expenses reasonably incurred in their defense, in case the Company fails to provide such defense. By participating in this Plan, each Eligible Employee agrees to release and hold harmless each of the Company and any affiliates (and their respective directors, officers and employee), the Board and the Committee, from and against any tax or other liability, including without limitation, interest and penalties, incurred by the Eligible Employee in connection with his participation in the plan.
7.14	Successors. All obligations of the Company under the plan with respect to Annual Incentive Awards granted hereunder shall be binding on any successor to the Company, whether the existence of such successor is a result of a direct or indirect purchase, merger, consolidation or otherwise, of all or substantially all of the business and/or assets of the Company.

EX-10

Craig Parenzan Termination Agreement
Termination Agreement between the Company and Craig Parenzan made as part of his hiring process:
	If you are terminated by the Company without cause during your first two years of employment, you will receive a severance payment of 2 times your base salary. If you are terminated without cause during your third year of employment, you will receive a severance payment of 1.5 times your base salary. If you are terminated after that time without cause, you will receive a severance payment of 75% of your base salary. In addition, under any of these scenarios you will receive a prorata portion of your target management incentive plan payout. "Cause" and "Constructive Termination Without Cause" shall be defined as follows:
Cause:
	For purposes of this Agreement, Executive's employment may be terminated for "cause" if (i) Executive is convicted of a felony (ii) in the reasonable determination of the Board, Executive has committed an intentional act of fraud, embezzlement, or theft in connection with Executive's duties in the course of his employment with the Company, or engaged in gross mismanagement or gross negligence in the course of his employment with the Company or (iii) Executive intentionally breached his obligations under this Agreement, including inattention to or neglect of duties and shall not have remedied such breach within 30 days after receiving written notice from the Board specifying the details thereof, provided, however, that in any case under this clause (iii) the act or failure to act by Executive is materially harmful to the business of the Company. For purposes of this Agreement, an act or omission on the part of the Executive shall be deemed "intentional" only if was done by Executive in bad faith, not merely an error in judgment and without reasonable belief that the act or omission was in the best interest of the Company.
Constructive Termination Without Cause
	For purposes of this Agreement, resignation by Executive for good reason ("Constructive Termination Without Cause") shall mean a termination of Executive's employment at his initiative following the occurrence, without Executive's written consent, of (i) a material diminution in Executive's duties, responsibilities, authority, or status, or a failure of Executive to have a position reporting directly to the President/CEO or to the Board (ii) a reduction to any amount of Executive's Base Salary, (iii) the assignment to Executive of duties or obligations which are materially inconsistent with the duties, responsibilities, authority, or status of his position as Senior Vice President or which materially impair Executive's ability to function in his then current position, or (iv) a failure of the Company to comply with any of the materials terms of this Agreement Letter.