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     June 30, 2001    

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

For the transition period from _______ to _______

Commission file number     1-8222

          Central Vermont Public Service Corporation          
(Exact name of registrant as specified in its charter)

        Incorporated in Vermont                          03-0111290        
(State or other jurisdiction of                     (I.R.S. Employer
incorporation or organization)                    Identification No.)

        77 Grove Street, Rutland, Vermont            05701        
(Address of principal executive offices)       (Zip Code)

                              802-773-2711                              
(Registrant's telephone number, including area code)

                                                                                                         
(Former name, former address and former fiscal year, if changed since last report)

      Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes   X     No       

      Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. As of July 31, 2001 there were outstanding 11,548,827 shares of Common Stock, $6 Par Value.

Page 1 of 29

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Form 10-Q Table of Contents
PART I.		FINANCIAL INFORMATION		PAGE
Item 1.	Financial Statements
		Consolidated Statement of Income and Retained Earnings for the three and six    months ended June 30, 2001 and June 30, 2000		3
		Consolidated Balance Sheet as of June 30, 2001 and December 31, 2000		4
		Consolidated Statement of Cash Flows for the six months ended June 30, 2001    and June 30, 2000		5
		Notes to Consolidated Financial Statements		6
Item 2.	Management's Discussion and Analysis of Financial    Condition and Results of Operations		16
Item 3.		Quantitative and Qualitative Disclosures about Market Risk		27
PART II.		OTHER INFORMATION		28
SIGNATURE				29

Page 2 of 29

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		Six Months Ended
	June 30		June 30
	2001	2000		2001	2000
Operating Revenues	$73,882	$ 73,867		$151,914	$173,816
Operating Expenses
Operation
Purchased power	34,924	44,432		74,374	98,008
Production and transmission	5,347	6,811		11,983	13,314
Other operation	10,687	10,181		22,123	20,863
Maintenance	4,576	3,408		9,201	6,233
Depreciation	4,263	4,223		8,513	8,506
Other taxes, principally property taxes	2,910	2,818		6,012	5,843
Taxes on income	3,656	(83)		6,063	6,408
Total operating expenses	66,363	71,790		138,269	159,175
Operating Income	7,519	2,077		13,645	14,641
Other Income and Deductions
Equity in earnings of affiliates	696	731		1,358	1,477
Allowance for equity funds during construction	14	16		32	42
Other income, net	(7,815)	1,607		(7,298)	(1,456)
Benefit (provision) for income taxes	3,342	(440)		3,175	823
Total other income and deductions, net	(3,763)	1,914		(2,733)	886
Total Operating and Other Income	3,756	3,991		10,912	15,527
Interest Expense
Interest on long-term debt	3,278	3,623		6,488	7,188
Other interest	159	103		217	131
Allowance for borrowed funds during construction	(7)	(9)		(16)	(25)
Total interest expense, net	3,430	3,717		6,689	7,294
Net Income	326	274		4,223	8,233
Retained Earnings at Beginning of Period	81,885	79,885		78,423	72,371
Retained Earnings before Dividends	82,211	80,159		82,646	80,604
Cash Dividends Declared
Preferred Stock	424	890		848	1,335
Common Stock	5,081	5,049		5,084	5,049
Total dividends declared	5,505	5,939		5,932	6,384
Other Adjustments	269	(168)		261	(168)
Retained Earnings at End of Period	$76,975	$ 74,052		$ 76,975	$  74,052
(Losses) Earnings Available For Common Stock	(98)	(171)		3,375	7,343
Average Shares of Common Stock Outstanding	11,546,937	11,476,556		11,538,961	11,471,680
(Losses) Earnings Per Basic and Diluted  Share of Common Stock	(.01)	(.01)		.29	.64
Dividends Paid Per Share of Common Stock	$      .22	$       .22		$       .44	$        .44

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)

	June 30	December 31
	2001	2000
Assets
Utility Plant, at original cost	$481,231	$478,324
Less accumulated depreciation	191,855	183,828
	289,376	294,496
Construction work in progress	17,921	15,197
Nuclear fuel, net	1,120	1,283
Net utility plant	308,417	310,976
Investments and Other Assets
Investments in affiliates, at equity	24,417	24,527
Non-utility investments	53,521	46,591
Non-utility property, less accumulated depreciation	2,494	2,172
Total investments and other assets	80,432	73,290
Current Assets
Cash and cash equivalents	41,541	47,986
Special deposits	121	118
Accounts receivable, less allowance for uncollectible accounts             ($2,608 in 2001 and $1,655 in 2000)	21,155	25,006
Unbilled revenues	13,762	17,142
Materials and supplies, at average cost	3,770	3,702
Prepayments	1,279	2,593
Other current assets	6,084	6,511
Total current assets	87,712	103,058
Regulatory Assets	38,049	45,797
Other Deferred Charges	9,551	6,717
Total Assets	$524,161	$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	48,178	45,810
Accumulated other comprehensive income	(608)	(269)
Deferred compensation plans - employee stock ownership plans	(2,300)	(358)
Treasury stock (238,021 shares, and 277,868, respectively, at cost)	(3,105)	(3,624)
Retained Earnings	76,975	78,423
Total Common Stock Equity	189,855	190,697
Preferred and preference stock	8,054	8,054
Preferred stock with sinking fund requirements	15,000	16,000
Long-term debt	159,753	152,975
Capital lease obligations	13,480	13,978
Total capitalization	386,142	381,704
Current Liabilities
Current portion of long - term debt	5,194	4,205
Accounts payable	3,794	6,407
Accounts payable - affiliates	9,886	13,523
Accrued income taxes	0	1,428
Dividends declared	2,541	2,532
Nuclear decommissioning costs	2,348	2,214
Disallowed purchased power costs	0	2,934
Other current liabilities	16,628	23,117
Total current liabilities	40,391	56,360
Deferred Credits
Deferred income taxes	40,221	43,779
Deferred investment tax credits	5,853	6,049
Nuclear decommissioning costs	13,443	14,737
Other deferred credits	38,111	37,209
Total deferred credits	97,628	101,774
Commitments and Contingencies
Total Capitalization and Liabilities	$524,161	$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)

	Six Months Ended June 30
	2001	2000
Cash Flows Provided (Used) By:
Operating Activities
Net income	$   4,223	$   8,233
Adjustments to reconcile net income to net cash       provided by operating activities
Equity in earnings of affiliates	(1,358)	(1,477)
Dividends received from affiliates	1,417	1,914
Equity in earnings from non-utility investment	(2,729)	2,028
Distribution of earnings from non-utility investments	2,265	2,793
Depreciation	8,513	8,506
Regulatory Asset write-off	9,000	-
Amortization of capital leases	545	544
Deferred income taxes and investment tax credits	(3,062)	(4,151)
Net deferral and amortization of nuclear replacement            energy and maintenance costs	(5,273)	3,038
Amortization of conservation and load management costs	2,036	2,610
Decrease in accounts receivable and unbilled revenues	8,486	23,389
Decrease in accounts payable	(6,030)	(10,460)
Increase in accrued income taxes	(1,859)	(1,682)
Change in other working capital items	(7,209)	(889)
Other, net	(888)	(78)
Net cash provided by operating activities	8,077	34,318
Investing Activities
Construction and plant expenditures	(7,126)	(6,113)
Conservation and load management expenditures	(260)	(606)
Return of capital	93	93
Non-utility investments	(7,602)	(3,507)
Other investments, net	(392)	9
Net cash used for investing activities	(15,287)	(10,124)
Financing Activities
Short-term debt, net	(11)	2
Long-term debt, net	6,779	807
Common and preferred dividends paid	(5,924)	(5,936)
Reduction in capital lease obligations	(545)	(544)
Sale of treasury stock	466	28
Net cash provided (used) by financing activities	765	(5,643)
Net (Decrease) Increase In Cash and Cash Equivalents	(6,445)	18,551
Cash and Cash Equivalents at Beginning of Year	47,986	35,461
Cash and Cash Equivalents at End of Year	$   41,541	$   54,012
Supplemental Cash Flow Information
Cash paid during the year for:
Interest (net of amounts capitalized)	$    6,309	$    6,946
Income taxes (net of refunds)	$    7,991	$  11,379

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

Derivative Instruments: 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 (Hydro-Quebec Sellback #3). This contract has been determined to be a derivative under FAS 133. On April 11, 2001 the Vermont Public Service Board ("PSB") approved an Accounting Order which allows the fair valuation adjustment of this contract to be deferred on the balance sheet as either a deferred asset or liability. In the first quarter of 2001, this derivative had an estimated fair market value of approximately a $7.5 million unrealized loss which was recorded on the Consolidated Balance Sheet along with an offsetting deferred asset. In the second quarter of 2001, the Company adjusted its valuation methodology for this derivative which resulted in a fair market value of approximately a $1.4 million unrealized loss. The change in estimated fair market value has been recorded in Other deferred credits in the accompanying June 30, 2001 Consolidated Balance Sheet. In the second quarter of 2001, the Company recorded an offsetting deferred asset for the change in estimated fair market value of this contract, which is reflected in the accompanying Consolidated Balance Sheet in Other deferred charges.

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

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Note 2 - Regulatory Assets

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

	June 30	December 31
	2001	2000
Conservation and load management	$ 4,738	$10,212
Restructuring costs	51	2,472
Nuclear refueling outage costs	7,176	1,928
Income taxes	6,355	7,047
Year 2000 costs and technologies initiatives	87	2,322
Dismantling costs:
Maine Yankee nuclear power plant	10,744	11,505
Connecticut Yankee nuclear power plant	4,954	5,446
Hydro-Quebec arbitration costs, net of   deseasonalized revenue impact for 2000	2,531	2,531
Unrecovered plant and regulatory study costs	1,413	1,510
Other regulatory assets	-	824
	$38,049	$45,797

     In the rate order approved by the PSB on June 26, 2001, the Company agreed to take a one-time write-off of certain regulatory assets, as agreed with the DPS. In the second quarter of 2001, the Company wrote-off $9.0 million (pre-tax) of regulatory assets related to Conservation and load management, Year 2000 costs and technologies initiatives, Restructuring costs, and other costs. In addition, the Company has agreed that all amounts collected based on the award issued by the Hydro Quebec arbitration panel, or any settlement agreement with Hydro-Quebec, shall be applied first to reduce the balance of the deferred costs related to the ice storm arbitration, with the remaining balance applied to reduce other regulatory asset accounts as specified by the DPS and approved by the PSB. See Note 4 for discussion of the rate case settlement and Note 6 for discussion of the Hydro Quebec contract. In July 2001, the Company received its share of the settlement with Hydro-Quebec of ap proximately $4.3 million, which will be recorded in the third quarter of 2001. Vermont Yankee and Millstone Unit #3 had scheduled refueling outages during the first six months of 2001. During regular nuclear refueling outages, the incremental costs attributable to replacement energy purchased from NEPOOL or other parties in New England and maintenance costs are deferred and amortized ratably to expense until the next regularly scheduled refueling shutdown.

Note 3 - Investments in Affiliates

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

Vermont Yankee Nuclear Power Corporation:

	Three Months Ended June 30		Six Months Ended June 30
	2001	2000	2001	2000
Operating revenues	$ 57,032	$ 44,702	$ 97,995	$ 85,394
Operating income	$  2,625	$  4,027	$  6,082	$  7,910
Net income	$  1,573	$  1,639	$  3,124	$  3,383
Company's equity in net income	$    487	$    524	$    971	$  1,060

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Vermont Electric Power Company:

	Three Months Ended June 30		Six Months Ended June 30
	2001	2000	2001	2000
Operating revenues	$ 8,548	$ 7,425	$ 15,718	$ 14,140
Operating income	$   798	$   698	$  1,539	$  1,368
Net income	$   309	$   310	$    552	$    583
Company's equity in net income	$   153	$   158	$    300	$    299

Note 4 - Retail Rates

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

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

     In response to the Company's September 1997 rate increase filing, the PSB decided to appoint an independent investigator to examine the Company's decision to buy power from Hydro-Quebec. The Company made a filing with the PSB stating that the PSB as well as other parties should be barred from reviewing past decisions because the PSB already examined the Company's decision to buy power from Hydro-Quebec in a 1994 rate case in which the Company was penalized for "improvident power supply management." During February 1998, the 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 contrac t in 1991. The Company argued its position before the Vermont Supreme Court.

     On June 12, 1998, the Company filed with the PSB for a 10.7% retail rate increase that supplanted the September 22, 1997 rate increase request of 6.6%, to be effective March 1, 1999. On October 27, 1998, the Company reached an agreement with the DPS regarding the June 1998 retail rate increase request providing for a temporary rate increase in the Company's Vermont retail rates of 4.7% or $10.9 million on an annualized basis beginning with service rendered on or after January 1, 1999. The agreement was approved by the PSB on December 11, 1998.

     The 4.7% rate increase was subject to retroactive or prospective adjustment upon future resolution of issues arising under the Hydro-Quebec and the Vermont Joint Owners ("VJO") Power Contract. The agreement temporarily disallowed approximately $7.4 million (based on 1999 power costs) of the Company's purchased power costs under the VJO Power Contract. As a result of the 4.7% rate increase agreement, during the fourth quarters of 1998 and 1999, the Company recorded pre-tax losses of $7.4 million and $2.9 million, respectively, for disallowed purchased power costs, representing the Company's estimated under recovery of power costs, prior to further resolution, under the VJO Power Contract for 1999 and the first quarter of 2000, respectively. In 2000, an additional $11.5 million pre-tax loss was recorded for the estimated under recovery of Hydro-Quebec power costs for the second, third and fourth quarters of 2000, and the first quarter of 2001. In the first quarter of 2 001, an additional $2.9 million pre-tax loss was recorded for the estimated under recovery of Hydro-Quebec power costs for the second quarter of 2001. In the second quarter of 2001, the Company reversed its $2.9 million pre-tax liability related to estimated under recovery of Hydro-Quebec power costs for the second quarter of 2001, and discontinued the accrual for future under recovery of those costs. Based on the favorable outcome of the Company's June 26, 2001 rate order, which is described below, the Company will discontinue recording losses for future under recovery of Hydro-Quebec power costs.

Page 8 of 29

     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.

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

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

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

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

     On June 26, 2001 the PSB issued an order on the Company's rate case settlement with the DPS. In addition to the provisions outlined above, the approved rate order requires the Company to return up to $16 million to ratepayers in the event of a merger, acquisition or asset sale. As a result of the rate order, the 3.95% rate increase became effective with bills rendered July 1, 2001, and the Company recorded a $5.3 million after-tax loss to write-off certain regulatory assets as agreed to in the settlement. The Company was able to accept the 3.95% rate increase versus the 7.6% increase it requested since 1) regulatory asset amortizations will decrease approximately $3.5 million, on a twelve month basis, due to the $9 million one-time write-off of regulatory assets and 2) Vermont Yankee decommissioning costs decreased approximately $1.9 million, on a twelve month basis, after the rate case was filed as a result of an agreement in principle between Vermont Yankee and the secon dary purchasers. See Management's Discussion and Analysis, Nuclear Matters, Vermont Yankee.

     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 were reduced, while summer rates were increased. The rate design change was revenue neutral over a 12-month period. The additional 2000 revenues, resulting from implementing this change in mid-year, were applied to reduce or eliminate certain regulatory assets, as ordered by the PSB.

New Hampshire Retail Rates: Connecticut Valley 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 totaling approximately $1.3 million on a pre-tax basis. This determination was based on various legal and regulatory actions including the February 28, 1997 NHPUC Final Plan to restructure the electric utility industry in New Hampshire, a supplemental order which required Connecticut Valley to give notice to cancel its contract with the Company and denied stranded cost recovery related to this power contract, and a December 3, 1998 Court of Appeals decision stating that Connecticut Valley's rates could be reduced to the level prevailing on December 31, 1997. The Company's petition for rehearing with the Court of Appeals as well a petition for writ of certiorari with the United States Supreme Court were subsequently denied.

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

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

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

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

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

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

"the district court may defer vacation of this injunction against the refund order for up to 90 days. If within that period it has decided the merits of the request for a permanent injunction in a way inconsistent with 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.

Page 10 of 29

     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.

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

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

     On May 1, 2001, pursuant to a New Hampshire law, Connecticut Valley's customers became subject to an Electricity Consumption Tax ("ECT"), and Connecticut Valley was no longer subject to the New Hampshire Franchise Tax, but began to incur the New Hampshire Business Profits Tax. Pursuant to an NHPUC directive, in April 2001 Connecticut Valley filed tariff pages to reflect these tax changes in rates. The NHPUC suspended all tariff pages but the ECT. Subsequently NHPUC Staff and Connecticut Valley entered into a Stipulation that would make the Company whole while resulting in a zero overall rate change effective September 1, 2001. A hearing was held July 24, 2001 and the NHPUC is expected to issue an order approving the Stipulation.

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, and if Connecticut Valley is forced to terminate its relationship as a wholesale customer of the Company, it is possible that the Company would be required to recognize a pre-tax loss under this contract totaling approximately $44.7 million as of December 31, 2000. The Company would also be required to write-off approximately $1.4 million (pre-tax) in regulatory assets associated with its wholesale business as of June 30, 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.

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

Wheelabrator Power Contract: Connecticut Valley purchases power from several Independent Power Producers ("IPP's"), who own qualifying facilities as defined by the Public Utility Regulatory Policies Act of 1978. In 2000, under long-term contracts with these qualifying facilities, Connecticut Valley purchased 39,998 mWh, 94% of which was purchased from Wheelabrator Claremont Company, L.P., ("Wheelabrator") who owns a solid waste plant. Connecticut Valley had filed a complaint with FERC stating its concern that Wheelabrator has not been a qualifying facility since the plant began operation. On February 11, 1998, the FERC issued an Order denying Connecticut Valley's request for a refund of past purchased power costs and lower future costs. The Company filed a request for rehearing with the FERC on March 13, 1998, which was denied. Subsequently, Connecticut Valley appealed to the D.C. Circuit Court of Appeals, which denied the Company's appeal, but indicated that the Company could seek relief from the NHPUC. On May 12, 2000, the Company filed a petition with the NHPUC seeking (1) to amend the contract to permit purchase of net, rather than gross, output of the plant and (2) a refund, with interest, of past purchases of the difference between net and gross output.

     In December 2000 and January 2001, Wheelabrator, the New Hampshire/Vermont Solid Waste District, and several Connecticut Valley residential customers filed with the NHPUC to intervene. The Office of Consumer Advocate and the NHPUC Staff are automatic parties. A Prehearing Conference was held before the NHPUC on January 4, 2001, at which time each party provided preliminary position statements with regard to the petition. In February and March 2001 the parties filed briefs on the legal issues and Wheelabrator filed a motion to dismiss. The Company cannot predict when the NHPUC will issue a decision on the legal issues or the motion to dismiss or on the outcome of this matter.

Note 5 - Environmental

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

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

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

     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

Page 12 of 29

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 VT in a joint effort to develop a mutually acceptable solution.

Brattleboro Manufactured Gas Facility From the early to late 1940's, the Company owned and operated a manufactured gas facility in Brattleboro, Vermont. The Company commissioned an environmental site assessment in late 1999 upon request by the State of New Hampshire. In April 2000, the Company presented the assessment findings to the States of New Hampshire and Vermont and the town of Brattleboro. The State of Vermont concluded that additional semi-annual site monitoring is necessary and that the Company must develop a corrective action plan. The Company will submit a corrective action plan in the third quarter of 2001, expects to receive State of Vermont approval of the corrective action plan in 2001 and will implement the plan thereafter. At this time the Company has not finalized an estimate of its potential liability at this site.

Dover, New Hampshire, Manufactured Gas Facility In late 1999, the Company was contacted by Public Service of New Hampshire ("PSNH") with respect to this site. PSNH alleges the Company is partially liable for remediation of this site. PSNH's allegation is premised on the fact that prior to PSNH's purchase of the facility, it was operated by Twin State Gas and Electric ("Twin State"). Twin State merged with the Company on the same day the facility was sold to PSNH. The Company proposed, and PSNH accepted, an agreement that calls for an environmental mediator to assist in a non-binding evaluation of the Company's liability. In December 2000, PSNH submitted a work plan to the State of New Hampshire for further investigation of this site. The Company agreed, with reservations, to participate on a limited basis in the development and completion of that work since the State of New Hampshire considers the Company, along with others, as potentially responsible parties at the site. The work pl an received state review and approval will likely occur in the third quarter of 2001.

     A mediator on the issue of liability was chosen in April 2001 and the mediation concluded on July 18, 2001. Without admitting liability, both the Company and PSNH agreed to participate in the site remediation for those years Twin State was responsible. The cost of the remediation, the extent to which there are other potentially liable parties, and the amount of insurance recovery are yet to be determined. Phase II of the proposed mediation will occur in late October 2001 among all participating potentially responsible parties. At this time, the Company is unable to estimate its potential liability at this site.

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

     As of June 30, 2001, a reserve of $9.5 million exists which represents management's best estimate of the costs to remediate the sites discussed above.

Note 6 - Hydro Quebec Power Contract

     The Company is purchasing varying amounts of power from Hydro-Quebec under the VJO contract through 2016. There are specific contractual step up provisions that provide that in the event any VJO member fails to meet its obligation under the contract with Hydro-Quebec, the balance of the VJO participants, including the Company, will "step up" to the defaulting party's share on a pro-rata basis. As of December 31, 2000 the Company's VJO obligation is approximately $937 million on a nominal basis over the term of the contract ending in 2016. The total VJO contract obligation on a nominal basis over the term of the contract is approximately $2.2 billion.

     During January 1998, a significant ice storm affected parts of New York, New England and the Province of Quebec, Canada. This storm damaged major components of the Hydro-Quebec transmission system over which power is supplied to Vermont under the VJO Power Contract with Hydro-Quebec. This resulted in a 61-day interruption of a significant portion of scheduled contractual energy deliveries into Vermont. The ice storm's effect on Hydro-Quebec's transmission system caused the VJO to examine Hydro-Quebec's overall reliability and ability to deliver energy. On the basis of that examination, the VJO determined that Hydro-Quebec had been and remained unable to make available capacity with the degree of firmness required by the VJO Power Contract. That determination prompted the VJO to initiate an arbitration proceeding. In the arbitration, the VJO sought to terminate the contract, recover damages associated with Hydro-Quebec's failure to comply with the contract, and recover c apacity 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.

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     On April 17, 2001, the Company received a decision in the arbitration proceeding relating to the failure by Hydro-Quebec to deliver power during the outage in 1998. The decision stated that the long-term power supply contract between Hydro-Quebec and the Vermont utilities remains in effect, that Hydro-Quebec is required to reimburse the Vermont utilities for capacity payments made during the outage for power not delivered and ordered a refund to the VJO, valued at up to approximately $20 million plus interest, which amount would be adjusted downward to reflect either actual deliveries by HQ in the first quarter of 1998 or an agreement by the parties.

     In accordance with a PSB Accounting Order, the Company has deferred legal, consulting and related costs associated with this arbitration of approximately $6.3 million at June 30, 2001. These deferred costs have been offset by incremental revenue of $3.8 million, resulting from the implementation of deseasonalized rates on July 1, 2000 through December 31, 2000, as directed by the PSB. As part of the Company's June 26, 2001 rate order by the DPS, 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.

     On July 19, 2001, Hydro-Quebec and the VJO agreed to a final settlement of the arbitration issues. Under the settlement, the VJO will continue to receive power and energy from Hydro-Quebec under this contract through 2016. As part of the settlement, Hydro Quebec has made a $9 million payment to the VJO in July 2001, of which the Company's share was approximately $4.3 million (pre-tax) that will be recorded in the third quarter of 2001.

Note 7 - Segment Reporting

     The Company's reportable operating segments include Central Vermont Public Service Corporation ("CV") which engages in the purchase, production, transmission, distribution and sale of electricity in Vermont; Connecticut Valley Electric Company Inc. ("CVEC") which distributes and sells electricity in parts of New Hampshire; ("Catamount") 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 w hose purpose is to own, acquire, buy, sell and lease real and personal property and interests therein related to the utility business.

     The intersegment sales and services for each jurisdiction are based on actual rates or current costs. The Company evaluates performance based on stand-alone operating segment net income.

     Financial information by industry segment for the three and six months ended June 30, 2001 and 2000, is as follows (dollars in thousands):

					Reclassification
	CV	CVEC			and Consolidating
Three months ended June 30	VT	NH	Catamount	SmartEnergy	Other (1)	Entries	Consolidated
2001
Revenues from external customers	$ 68,644	$ 5,240	$     78	$   551	$    -	$  631	$ 73,882
Intersegment revenues	2,749	-	-	-	-	2,749	-
Net income (loss)	207	13	170	(66)	2	-	326
Total assets	455,177	12,225	54,144	6,479	318	4,182	524,161
2000
Revenues from external customers	$ 69,232	$ 4,637	$    125	$    768	$    -	$  895	$ 73,867
Intersegment revenues	3,322	-	-	-	-	3,322	-
Net income (loss)	44	(263)	40	450	3	-	274
Total assets	489,936	12,245	46,039	5,544	307	6,252	547,819

1. Includes a segment below the quantitative threshold.

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					Reclassification
	CV	CVEC			and Consolidating
Six months ended June 30	VT	NH	Catamount	SmartEnergy	Other (2)	Entries	Consolidated
2001
Revenues from external customers	$141,136	$10,781	$   131	$ 1,042	$    -	$1,176	$151,914
Intersegment revenues	5,930	-	-	-	-	5,930	-
Net income (loss)	3,802	120	526	(229)	4	-	4,223
Total assets	455,177	12,225	54,144	6,479	318	4,182	524,161
2000
Revenues from external customers	$164,170	$ 9,649	$   224	$ 1,656	$    -	$1,883	$173,816
Intersegment revenues	6,457	-	-	-	-	6,457	-
Net income (loss)	10,426	(154)	297	(2,341)	5	-	8,233
Total assets	489,936	12,245	46,039	5,544	307	6,252	547,819

1. Includes a segment below the quantitative threshold.

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION

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

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

Earnings Overview

     The Company recorded net income of $0.3 million, or a loss of $.01 per basic and diluted share of common stock, for the second quarter of 2001 compared to net income of $0.3 million, or a loss of $.01 per basic and diluted share of common stock, for the second quarter of 2000.

     During the second quarter of 2001, the Company's rate order approved by the PSB on June 26, 2001, permanently resolved the uncertainty over the future recovery of Hydro-Quebec contract costs putting an end to future Hydro-Quebec power cost disallowances. The rate order resulted in a one-time $5.3 million after-tax, or $.46 per share of common stock, write-off of certain regulatory assets, partially offset by a $1.7 million after-tax, or $.15 per share of common stock, favorable impact due to the elimination of under recovery of costs in the third quarter of 2001 related to the Hydro-Quebec power contract. Additionally, the Company recognized a one-time reversal of charges for estimated installed capability ("ICAP") deficiency charges in ISO-New England ("ISO-NE") of $1.5 million after-tax, or $.13 per share of common stock. Excluding these items, the Company had second quarter 2001 pro-forma net income of $2.4 million, or $.17 per basic and diluted share of common stock. < /P>

     A breakdown of the factors impacting second quarter 2001 earnings compared to second quarter 2000 earnings follows:

• the Company's June 26, 2001 rate order resulting in a one-time write-off of $5.3 million after-tax, or $.46 per share of common stock, of certain regulatory assets and the elimination of charges for the under recovery of costs related to the Hydro-Quebec power contract which resulted in a favorable $1.7 million after-tax impact, or $.15 per share of common stock,

• lower net power costs of $1.7 million after-tax, or $.15 per share of common stock, primarily resulting from a one-time reversal of accrued power costs of $1.5 million after-tax, for estimated ICAP deficiency charges in ISO-NE due to the resolution of a December 2000 FERC Order,

• higher utility revenues of $2.7 million after-tax, or $.23 per share of common stock, primarily resulting from higher average retail revenues in the second quarter of 2001 compared to the same period in 2000 as a result of a PSB Order which deseasonalized or equalized the Company's winter/summer rates beginning July 1, 2000, offset by lower utility revenues of $0.3 million after-tax, or $.02 per share of common stock, primarily resulting from a 2.2% (11,968mWh) decrease in retail mWh sales; and

• losses in the second quarter of 2001 at SmartEnergy Services, Inc. of $0.1 million after-tax, or $.01 per share of common stock, compared to earnings in the second quarter of 2000 of $0.5 million after-tax, or $.04 per share of common stock, primarily related to higher business development costs.

     For the first six months ended June 30, 2001 the Company had net income of $4.2 million, or $.29 per basic and diluted share of common stock, compared to net income of $8.2 million, or $.64 per basic and diluted share of common stock, for the first six months ended June 30, 2000. Excluding the second quarter 2001 nonrecurring items described above, the Company's pro-forma net income for the six months ended June 30, 2001 was $6.3 million, or $.47 per basic and diluted share of common stock, compared to net income of $8.2 million, or $.64 per basic and diluted share of common stock, for the first six months ended June 30, 2000.

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     Lower first six months 2001 earnings compared to the same period last year resulted primarily from the following factors:

• the Company's June 26, 2001 rate order resulting in a one-time write-off of $5.3 million after-tax, or $.46 per share of common stock, of certain regulatory assets and the elimination of charges for the under recovery of costs related to the Hydro-Quebec power contract which resulted in a favorable $1.7 million after-tax impact, or $.15 per share of common stock,

• lower net power costs of $1.9 million after-tax, or $.16 per share of common stock, primarily resulting from a one-time reversal of accrued power costs of $1.5 million after-tax, for estimated ICAP deficiency charges in ISO-NE due to the resolution of a December 2000 FERC Order,

• lower utility revenues of $1.2 million after-tax, or $.10 per share of common stock, primarily resulting from lower average retail revenues in the first six months of 2001 compared to the same period in 2000 as a result of a PSB Order which deseasonalized or equalized the Company's winter/summer rates beginning July 1, 2000, offset by lower utility revenues of $0.9 million after-tax, or $.08 per share of common stock, primarily resulting from a 2.2% (25,591mWh) decrease in retail mWh sales,

• lower net losses in the first six months of 2001 at SmartEnergy Services, Inc. of $2.1 million after-tax, or $.18 per share of common stock, and higher operating and other costs of $2.2 million after-tax, or $.19 per share of common stock, primarily due to higher service restoration costs related to storm activity in the first quarter of 2001.

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

Results of Operations

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

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

	Three Months Ended June 30
			Percentage			Percentage
	mWh Sales		Increase	Revenues (000's)		Increase
	2001	2000	(Decrease)	2001	2000	(Decrease)
Residential	215,823	217,813	(.9)	$ 28,104	$26,538	5.9
Commercial	220,468	221,892	(.6)	26,207	24,349	7.6
Industrial	101,448	110,015	(7.8)	8,281	8,222	.7
Other retail	1,586	1,573	.8	444	446	(.4)
Total retail sales	539,325	551,293	(2.2)	$ 63,036	$59,555	5.8
Resale sales:
Firm	460	439	4.8	$      36	$     33	9.1
Entitlement	39,897	79,389	(49.7)	2,742	2,798	(2.0)
Alliance	0	89,000	(100.0)	0	3,398	(100.0)
Other	157,405	205,026	(23.2)	6,398	7,106	(10.0)
Total resale sales	197,762	373,854	(47.1)	9,176	13,335	(31.2)
Other revenues	-	-	-	1,670	977	70.9
Total	737,087	925,147	(20.3)	$ 73,882	$73,867	-

	Six Months Ended June 30
			Percentage			Percentage
	mWh Sales		Increase	Revenues (000's)		Increase
	2001	2000	(Decrease)	2001	2000	(Decrease)
Residential	489,218	495,166	(1.2)	$  62,474	$  64,968	(3.8)
Commercial	452,813	452,491	.1	52,561	52,356	.4
Industrial	215,703	235,657	(8.5)	17,699	19,767	(10.5)
Other retail	3,128	3,139	(.4)	879	889	(1.0)
Total retail sales	1,160,862	1,186,453	(2.2)	$133,613	$137,980	(3.2)
Resale sales:
Firm	1,134	1,101	3.0	$     74	$      70	5.7
Entitlement	93,018	134,979	(31.1)	4,711	4,754	(.9)
Alliance	0	450,800	(100.0)	0	16,510	(100.0)
Other	238,832	361,936	(34.0)	10,210	11,606	(12.0)
Total resale sales	332,984	948,816	(64.9)	14,995	32,940	(54.5)
Other revenues	-	-	-	3,306	2,896	14.2
Total	1,493,846	2,135,269	(30.0)	$151,914	$173,816	(12.6)

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     Retail mWh sales for the second quarter of 2001 decreased 2.2% compared to the second quarter of 2000, and related revenues increased $3.5 million, or 5.8% compared to last year. The retail revenue variance is attributable to a $4.5 million favorable price variance primarily due to the impact of deseasonalized rates, implemented in July 2000, and an unfavorable $1.0 million impact of lower mWh sales primarily from the industrial sector which is partially offset by fewer short term power purchases included in the table below.

     For the first half of 2001, retail mWh decreased 2.2% or 25,591 mWh compared to the first half of 2000, primarily from the industrial sector. Revenues decreased 3.2% or $4.4 million compared to 2000 due to an unfavorable price variance as a result of deseasonalized rates and an unfavorable volume variance. Partially offsetting this decrease are fewer short term power purchases of approximately $1 million which are included in the table below.

     Wholesale mWh sales for the second quarter of 2001 decreased 47.1%, and revenues decreased 31.2% compared to last year mostly due to the discontinuance of the company's alliance with Virginia Power, the conclusion of a long term contract which ended in late 2000, and the scheduled 2001 Vermont Yankee refueling outage. 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. Entitlement resale sales decreased 49.7% due to the scheduled 2001Vermont Yankee refueling outage. Other resale sales decreased 23.2% or 47,621 mWh and revenues decreased $0.7 million or 10.0%. These sales, made on a short term basis, include sales to ISO-NE and other utilities in New England.

     For the first half of 2001 wholesale mWh sales decreased 64.9% or 615,832 mWh as a result of the discontinuance of the company's alliance with Virginia Power, the conclusion of a long-term contract which ended in late 2000, and the scheduled 2001 Vermont Yankee refueling outage.

     Other revenues for the second quarter of 2001 are higher than the second quarter of 2000 mainly due to the 2000 provision for rate refund of $0.5 million, for Connecticut Valley that was recognized in 2000.

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

	Three Months Ended June 30
	2001		2000
	Units	Amount	Units	Amount
Purchased and produced:
Capacity (mW)	444	$ 19,131	404	$ 24,001
Energy (mWh)	686,058	15,793	835,209	20,431
Total purchased power costs		34,924		44,432
Production fuel (mWh)   Total purchased power and production fuel costs	103,107	518 35,442	135,263	1,203   45,635
Less entitlement and other resale sales (mWh)	197,302	9,140	373,415	13,302
Net purchased power and production fuel costs		$ 26,302		$ 32,333

	Six Months Ended June 30
	2001		2000
	Units	Amount	Units	Amount
Purchased and produced:
Capacity (mW)	442	$41,516	432	$ 46,847
Energy (mWh)	1,428,685	32,858	1,989,504	51,161
Total purchased power costs		74,374		98,008
Production fuel (mWh)   Total purchased power and production fuel costs	173,758	1,474   75,848	251,262	2,056 100,064
Less entitlement and other resale sales (mWh)	331,850	14,921	947,715	32,870
Net purchased power and production fuel costs		$60,927		$ 67,194

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     Purchased and produced capacity (mW) decreased $4.9 million for the second quarter of 2001 versus last year, primarily due to the June 26, 2001 rate order which eliminated future disallowances for the under recovery of Hydro-Quebec power costs resulting in a $2.9 million reversal of the accrual for estimated under recovery of Hydro-Quebec costs in the second quarter of 2001, with no accrual for future under recovery of those costs in the third quarter of 2001. Additionally, the second quarter of 2001 included a $2.5 million one-time reversal of accrued power costs for estimated ICAP deficiency charges in ISO-NE due to resolution of a December 2000 FERC Order. Partially offsetting these decreases, were higher capacity purchases from the bilateral market.

     Purchased and produced energy (mWh) costs decreased $5.3 million for the second quarter of 2001 due to the discontinuance of the Company's alliance with Virginia Power, lower production from the Independent Power Producers, and a 2.2% decrease in retail sales compared to the second quarter of 2000.

     For the first six months ended June 30, 2001, net purchased power and production fuel costs decreased $6.3 million or 9.3% compared to the first six months ended June 30, 2000. The $6.3 million decrease is primarily related to lower capacity costs due to the June 26, 2001 rate order which eliminated future disallowances for the under recovery of Hydro-Quebec power costs resulting in a $2.9 million favorable impact from the reversal of the accrual for estimated under recovery of Hydro-Quebec costs in the second quarter of 2001, with no accrual for future under recovery of those costs in the third quarter of 2001 and the $2.5 million one-time reversal of accrued power costs for ICAP deficiency charges in ISO-NE due to resolution of a December 2000 FERC Order. Additionally energy costs decreased due to a 2.2% decrease in retail sales volume which resulted in approximately $1 million fewer short term purchases and the favorable impact of joint energy sale transactions with Hydr o-Quebec under the Hydro-Quebec 9600 power contract which expired on June 30, 2001. Partially offsetting this decrease were short-term purchases at higher rates due to lower output from the Company's wholly and joint owned units and the 2001 scheduled Vermont Yankee refueling outage.

NUCLEAR MATTERS

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

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

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

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

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

     On February 14, 2001, the 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

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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, which is currently in progress. 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 reflected in billings to sponsors and secondary purchasers, effective July 2001 but is contingent upon FERC approval. The timing of the FERC approval 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. 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 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.

     Maine Yankee, Connecticut Yankee and Yankee Atomic Decommissioning Costs Currently, costs billed to the Company by Maine Yankee, Connecticut Yankee and Yankee Atomic, including a provision for ultimate decommissioning of the units, are being collected from the Company's customers through existing retail and wholesale rate tariffs. The Company's share of remaining costs with respect to Maine Yankee and Connecticut Yankee's decisions to discontinue operation is estimated to be $10.7 million and $5.0 million, respectively, at June 30, 2001. These amounts are subject to ongoing review and revisions and are reflected in the accompanying Consolidated Balance Sheet both as regulatory assets and nuclear dismantling liabilities (current and non-current).

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

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

     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

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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 was appealed to and affirmed by the Vermont Supreme Court. The Company, the other moving utilities and the DPS had requested that the PSB issue an order requiring GMP's full participation in the PSB proceeding. The PSB declined to rule on the request but retained authority to require GMP to provide specific information or to submit any other specific 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 PSB's exercise of jurisdiction, as called under the Petition. The DPS also made a filing in support of jurisdiction. On June 1, 2001, the PSB Hearing Officer issued a Proposal for Decision ("PFD") on the PSB's jurisdiction to consider the Petition. The PFD recommends that the PSB find that it has jurisdiction to consider the relief sought under the Petition but that the PSB may be precluded from issuing orders reducing the lengths of a Purchasing Agent contract or requiring buy-outs or buy-downs. Docket participants filed comments on the PFD. A decision from the PSB on the jurisdictional issues is expected at any time.

     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. Docket participants have completed all briefing of the issues and 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 FERC ("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 argue that such reservations and related charges are prohibited under the regulations adopted by the State of Vermont to implement the Public Utilities Regulatory Policies Act of 1978. On April 4, 2001, the Company and the other Vermont utilities filed their response arguing that the IPP complaint should be dismissed on procedural grounds and opposing the IPPs allegations on the merits. By Order dated May 16, 2001, the Commission declined to grant the relief requested and instead found that the complaint was premature in light of the fact that the PSB has yet to rule on the dispute d issues in the proceeding open before it.

     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

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new licenses, the FERC is expected to impose conditions designed to address the impact of the projects on fish and other environmental concerns. The Company is unable to predict the specific impact of the imposition of such conditions, but capital expenditures and operating costs are expected to increase in the short term to meet these licensing obligations and net generation from these projects will decrease in future periods.

Production and transmission expenses The decrease in other production and transmission expenses of approximately $1.5 million in the second quarter of 2001 and approximately $1.3 million in the first half of 2001 resulted primarily from lower power management expenses.

Maintenance expenses The increase in maintenance expenses of $1.2 million in the second quarter of 2001 and $3.0 million the first six months of 2001 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 second quarter of 2001, these taxes increased as a result of an increase in pre-tax earnings and no material change in permanent differences for the period.

Other income and deductions Other income and deductions decreased for the second quarter and first six months of 2001. The decrease primarily resulted from the $9.0 million regulatory asset write-off as part of the June 26, 2001 rate order approved by the DPS and was partially offset by lower equity losses from non-utility subsidiary companies mostly related to SmartEnergy's equity in HSS.

Interest on long-term debt Interest on long-term debt decreased for the second quarter and first six months 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 $8.1 million and $34.3 million for the first six months ended June 30, 2001 and 2000, respectively.

     The Company ended the first six months of 2001 with cash and cash equivalents of $41.5 million, a decrease of $6.4 million from the beginning of the year. The decrease in cash for 2001 was the result of $8.1 million provided by operating activities, offset by $15.3 million used for investing activities and $0.8 million provided by financing activities.

     Operating Activities - Net income, depreciation, deferred income taxes and investment tax credits provided cash of $9.7 million. Approximately $1.6 million of cash was used for working capital and other operating activities.

     Investing Activities - Construction and plant expenditures used cash of approximately $7.1 million and Conservation and Load Management programs used $0.3 million, while $7.6 million was used for non-utility investments by the Company's subsidiaries and $0.3 million was required for other investing activities.

     Financing Activities - Dividends paid on common stock were $5.1 million, while preferred stock dividends were $0.8 million. Net long-term debt, primarily related to Catamount, provided $6.7 million of capital. In addition, a reduction in capital lease obligations required $0.5 million and sale of treasury stock provided $0.5 million.

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

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

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

1. Outlook: Stable
2. Outlook: Stable

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     On July 11, 2001, Fitch removed the Company from its "Rating Watch Negative" status because of the favorable resolution of the Company's rate order with the PSB. Fitch is currently assessing the impact of the rate order on the Company's current credit ratings.

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

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

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

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

     Financial obligations of the Company's subsidiaries are non-recourse to the Company. On April 25, 2001 the Company sought and in June 2001 the Company received unanimous approval from its First Mortgage Bondholders to enter into a 42d 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 SmartEnergy), from the term "subsidiary" under the Mortgage. The 42d Supplemental Indenture (amendment) eliminates the possibility of cross defaults under the First 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, experienced construction delays in the past which could have resulted in an opportunity for an event of default to be declared under the project's construction loa n agreement. A project loan event of default could have, in turn, caused a default under Catamount's $25 million revolving credit agreement. Absent the amendment from the First Mortgage Bondholders, a Catamount default under its $25 million credit agreement, if any, could have caused a cross default to the Company's First Mortgage Bonds. The First Mortgage amendment 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. The amendment imposes limitations on the level of the Company's future investment in non-regulated subsidiaries. Approval of the 42d Supplemental Indenture required the written consent of 66 2/3% of its outstanding First Mortgage Bonds.

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

Hydro-Quebec Contract

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

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

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, which became operational in July 2001. In

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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 up to a $5.0 million security interest in its stock, to secure the payment of potential cost overruns at the Gauley River Power project. An arbitration proceeding has begun related to delay issues, liquidated damages of $2.9 million and cost overruns of $14.0 million involving a Catamount subsidiary, the turbine supplier and the contractor. These construction delays could cause a default under Catamount's $25 million revolving credit agreement. In June 2001, the Company received unanimous approval from its outstanding First Mortgage Bondholders to enter into a 42d Supplemental Indenture to the Company's Mortgage to exclude its wholly owned non-regulated subsidiary from the term "subsidiary" under the First Mortgage, eliminating a cross default risk. The Gauley River Power project which is currently operating, incurred a $0.6 million liquidated damage liability to its primary purchased power contract hol der during July 2001, as a result of power production delays.

     Catamount's Fibrothetford equity investment has been reduced to zero as a result of losses incurred to date. As of June 30, 2001, losses are being applied to Catamount's note receivable balance. Catamount will also reserve against future interest income on the note receivable, which is expected to be approximately $1.3 million over the next twelve months, due to the uncertainty that it will be collected in the future. Fibrothetford is projecting a cash shortfall when the next senior debt principal payment is due September 30, 2001. Fibrowatt is negotiating an arrangement with the Non-Fossil Purchasing Agency to reduce that shortfall. Catamount's after-tax earnings were $0.2 million and $0.0 million for the second quarter of 2001 and 2000, respectively, and $0.6 million and $0.3 million for the first six months 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 income of $(0.1) million and $0.5 million for the second quarter of 2001 and 2000, respectively, and net losses of $0.2 million and $2.3 million for the first six months 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. In May 2001, SmartEnergy entered into a convertible loan agreement with HS S and Jupiter Capital. Under the agreement, SmartEnergy loaned HSS $2.0 million, and Jupiter Capital loaned HSS $5.0 million which, along with current debt balances and accrued interest, will convert to equity at the time HSS issues additional equity securities of $10 million. SmartEnergy's share of HSS's pre-tax loss for the second quarter of 2001 and 2000 was zero and $3.7 million, respectively. As of June 30, 2001, SmartEnergy's net investment in HSS is $3.3 million. SmartEnergy Control Systems, which is a wholly owned subsidiary of SmartEnergy, is currently in arbitration with Westfalia-Surge, the exclusive distributor that markets and sells its SmartDrive Control product, concerning the Company's claim that Westfalia-Surge has not conducted itself in accordance with the exclusive distributorship agreement between the parties. The SmartDrive Control product has generated approximately 95% of the sales revenue of SmartEnergy Control Systems. SmartEnergy Control Systems' revenues represent approximat ely $0.6 million of the total SmartEnergy revenues of approximately $2.5 million, on an annual basis.

Rates and Regulation

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

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

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Proposed Formation of a Holding Company

     In order to further prepare the Company for deregulation, and to insulate the Company from the risks of its various regulated and unregulated subsidiaries, 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 Energy and SmartEnergy, and their subsidiaries. The proposal has been revised to have Connecticut Valley Electric Company become a direct subsidiary of the holding company, rather than remain as a subsidiary of the Company. 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 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.

     On May 7, 2001, as part of the settlement in the June 26, 2001 rate order, the Company and the DPS agreed to develop and file a schedule for the consideration of the holding company structure for the Company, and to submit an agreement supporting the approval of affiliate transaction rules and codes of conduct for a new holding company. The PSB recently approved the schedule for the holding company docket, which schedule anticipates a settlement filing, if any, in September and sets forth a schedule for litigation, if necessary, beginning in December. The Company and the DPS are currently engaged in settlement discussions, although the Company cannot predict whether a settlement will be reached or whether the PSB will ultimately approve the Company's holding company proposal.

ELECTRIC INDUSTRY RESTRUCTURING

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

Vermont

     Recently, there have been three primary sources of Vermont governmental activity in attempting to restructure the electric industry in Vermont: (1) the Governor's Working Group, created by the Governor of Vermont; (2) the PSB's Docket No. 6140 through which the PSB considered 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.

Regional Transmission Organizations (RTO)

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

     On May 13, 1999, the FERC issued a notice of proposed rulemaking that would amend FERC's regulations under the Federal Power Act to facilitate the formation of regional transmission organizations ("RTO"). On December 20, 1999, the FERC issued Order No. 2000, which requires all public utilities that own, operate, or control interstate electric transmission to file a proposal for an RTO by October 15, 2000, or in the alternative, a description of any efforts by the utility to participate in an RTO, the reasons for not participating and any obstacles to participation, and any plans for further work toward such participation. The filing date for Order No. 2000 was extended to January 16, 2001 for utilities in regions with an existing independent system operator ("ISO"), e.g. ISO-New England.

     The Company, jointly with GMP, Citizens Utilities and Vermont Electric Power Co. ("VELCO"), filed its comments on the New England RTO proposal submitted by some of the New England transmission owners and ISO-NE on January 16, 2001.

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     On July 12, 2001 the FERC issued an order on the New England RTO proposal which found that the RTO proposed by the New England market participants would be insufficient in its proposed scope and regional configuration to effectively perform an RTO's required functions and to support competitive power markets. The FERC required that the participants in the proceedings involving the three proposed RTOs in the northeast, participate in mediation on forming a single Northeastern RTO. The FERC directed an Administrative Law Judge to mediate settlement discussions with the parties for a period of 45 days and file a report within 10 days after that 45-day period. The report is due on September 17, 2001.

     The Company will continue to negotiate with the New England transmission owners to develop an RTO, which meets the requirements of Order No. 2000.

     At this time, the Company has several options for joining an RTO, some of which do not require a transfer of assets. There can be no assurance as to the outcome of this matter, but FERC describes the RTO formation process as voluntary.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Competition - Risk Factors

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

     Historically, electric utility rates have been based on a utility's costs. As a result, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. 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 $38 million on a pre-tax basis as of June 30, 2001. In the second quarter of 2001, the Company wrote off $9 million ($5.3 million after-tax) of its regulatory assets as part of the July 26, 2001 approved rate order. Criteria that give rise to the discontinuance of SFAS No. 71 include (1) increasing competition that restricts the Company's ability to establish prices to recover specific costs and (2) a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation.

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

     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.

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PART II - OTHER INFORMATION

Item 1.	Legal Proceedings.
The Company is involved in litigation in the normal course of business, which the Company does not believe will have a material adverse effect on the financial position or results of operations.
Items 2, 3, and 4.		None.
Item 5.	None.
Item 6.	Exhibits and Reports on Form 8-K.
	(a)	List of Exhibits.
		10.84	Settlement Agreement effective date June 1, 2001 to which the Company is a party re: Vermont Yankee Nuclear Power Station.
	(b)	Item 5.	Other events, dated June 26, 2001 re: Approval of Memorandum of Understanding by the Vermont Public Service Board concerning the Company's pending rate case and recovery of cost associated with HQ.
			Dated June 28, 2001 re: Implementation of the Company's Forty-Second Supplemental Indenture to its First Mortgage.
			Dated July 19, 2001 re: Settlement agreement between the Vermont Joint Owners and Hydro-Quebec.

Page 28 of 29

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 August 10, 2001

Page 29 of 29

EX-10

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

Vermont Yankee Nuclear
Power Corporation






Boylston Municipal Light
Department, et al.,

           v.

Vermont Yankee Nuclear Power
Corporation, et al. )
)
)
)
)
)


)
)
)
)
)
)
) Docket Nos. EC00-46-000,
EC00-46-01, ER00-1027-000,
ER00-1027-001, ER00-1027-002,
ER00-1028-000, ER00-1028-001,
ER00-1029-000, and
ER00-1029-001





Docket No. EL00-86-000

SETTLEMENT AGREEMENT

Article I

BACKGROUND

1.1       Parties

            This Settlement Agreement ("Agreement") dated June 25, 2001, is made and sponsored jointly by and among Vermont Yankee Nuclear Power Corporation ("Vermont Yankee"), Cambridge Electric Light Company, Central Vermont Public Service Corporation, Central Maine Power Company, The Connecticut Light and Power Company, Green Mountain Power Corporation, New England Power Company, Public Service Company of New Hampshire, and Western Massachusetts Electric Company (the foregoing eight parties being referred to herein collectively as the "Sponsors"), the Vermont Department of Public Service ("VDPS"), Boylston Municipal Light Department, Braintree Electric Light Department, City of Chicopee Municipal Lighting Plant, Danvers Electric Division, Georgetown Municipal Light Department, Hingham Municipal Light Plant, City of Holyoke Gas & Electric Department, Hudson Light and Power Department, Hull Municipal Lighting Plant, Ipswich Municipal Light D epartment, Marblehead Municipal Light Department, Middleborough Gas and Electric Department, Middleton Municipal Light Department, North Attleborough Electric Department, Paxton Municipal Light Department, Peabody Municipal Light Plant, Shrewsbury's Electric Light Plant, Sterling Municipal Light Department, Taunton Municipal Lighting Plant, Wakefield Municipal Light Department, West Boylston Municipal Lighting Plant, and Westfield Gas & Electric Light Department (the foregoing twenty-two parties being referred to collectively herein as the "Massachusetts Municipals"), the Connecticut Municipal Electric Energy Cooperative ("CMEEC"), and, solely with respect to Article II and Article VI hereof, Vermont Electric Power Company ("VELCO"). Each of the foregoing signatories is referred to herein as a "Party" and they are referred to collectively herein as the "Parties."

1.2       Factual Background

(A)       Commission Proceedings

            On January 6, 2000, Vermont Yankee, VELCO, and AmerGen Vermont filed with the Commission certain applications and rate schedules associated with the proposed sale of the Vermont Yankee Nuclear Power Station (the "Plant"). Vermont Yankee currently sells the entire output of the Plant at wholesale to the Sponsors pursuant to wholesale power contracts on file with the Commission (the "Power Contracts"), and a portion of that output is resold by certain Sponsors to the Massachusetts Municipals, CMEEC, and other municipal and cooperative utilities pursuant to wholesale power contracts on file with the Commission (the "Secondary Power Contracts"). The rate schedules filed with the January 6, 2000 application included amendments to the Power Contracts to effect changes associated with the proposed sale of the Plant (the "2000 Amendatory Agreements"). On June 29, 2000, the Commission issued an order in Docket Nos. EC00-46-000, et al., granting the authorizations required under section 203 of the Federal Power Act, 16 U.S.C. Section 824b, in connection with the proposed sale of the plant, accepting the associated rate schedules for filing, and establishing hearing procedures and an investigation with respect to the 2000 Amendatory Agreements. Vermont Yankee Nuclear Power Corp., 91 FERC Paragraph 61,325 (2000) ("June 29 Order"). On July 31, 2000, the Massachusetts Municipals filed a petition for rehearing and request for clarification of the June 29 Order.

            On June 22, 2000, the Massachusetts Municipals filed a Complaint against Vermont Yankee and the Sponsors, alleging that Vermont Yankee had improperly collected certain transaction costs associated with the proposed sale of the Plant under the Power Contracts' formula rates and that the Massachusetts Municipals were entitled to certain refunds of amounts they had paid into Vermont Yankee's decommissioning trust funds. On August 31, 2000, the Commission issued an order in Docket No. EL00-86-000 setting the complaint for investigation and hearing and consolidating those proceedings with the proceeding in Docket No. ER00-1029-000 established in the June 29 Order. Boylston Municipal Light Dep't, et al. v. Vermont Yankee Nuclear Power Corp., 92 FERC Paragraph 61,185 (2000) ("August 31 Order").

            The consolidated proceedings were assigned to Presiding Administrative Law Judge Jacob Leventhal for hearing. At the participants' request, Administrative Law Judge Joseph R. Nacy was appointed as a Settlement Judge. Proceedings before Judge Leventhal were suspended.

(B)       Termination of Sale and Settlement

            The Parties and other participants in these consolidated proceedings have negotiated with the assistance of Judge Nacy and the Commission's Trial Staff to resolve their differences. During the course of those negotiations, the agreements for the sale of the Plant to AmerGen and the sale of certain transmission switchyard facilities to VELCO were terminated, following the failure of that transaction to obtain a necessary regulatory approval from the Vermont Public Service Board.

            As a result of the negotiations, the Parties have reached agreement on a settlement that would resolve (or defer to future proceedings) all pending issues in these consolidated proceedings. All terms of that settlement are set forth in this Agreement.

Article II

WITHDRAWAL OF APPLICATIONS AND

TERMINATION OF PROCEEDINGS RELATING

TO THE PROPOSED SALE OF THE PLANT

2.1       In light of termination of the agreements for the proposed sale of the Plant to AmerGen and certain transmission switchyard facilities to VELCO, and upon Commission Acceptance (i.e., final acceptance or approval of this Agreement without modification in accordance with Section 6.6 below), the Parties agree as follows:

2.1.1   The applications filed on June 6, 2000, as amended, in Docket Nos. EC00-46-000, et al., that were the subject of the June 29 Order, including, without limitation, the 2000 Amendatory Agreements, shall be deemed by the filing and Commission Acceptance of this Agreement to be withdrawn by the applicants;

2.1.2   All requests for rehearing of the June 29 Order shall be deemed by the filing and Commission Acceptance of this Agreement to be withdrawn;

2.1.3   The Complaint filed by the Massachusetts Municipals on June 22, 2000 in Docket No. EL00-86-000 that was the subject of the August 31 Order shall be deemed by the filing and Commission Acceptance of this Agreement: (a) to be satisfied and dismissed with respect to the claim regarding transaction costs, in accordance with Commission Rule 206(j); and (b) to be withdrawn without prejudice (as provided in Section 3.1.4) by the complainants with respect to all other claims; and

2.1.4   The submission of this Agreement should be treated by the Commission as a request by the Parties that the Commission vacate the June 29 Order and the August 31 Order and the Parties agree to urge the Commission to take that action.

2.2       The Parties agree that the withdrawal of applications, complaints and other pleadings in accordance with Section 2.1 is without prejudice to the right of any Party to submit in the future any application, complaint or other pleading and to take any position or present any claim or argument therein in connection with any new transaction for the sale or other disposition of the Plant.

Article III

REFUND ELIGIBILITY AND

TRANSACTION COSTS

3.1       Pursuant to Section 3.2 and Section 4.2, Vermont Yankee shall provide certain refunds and credits to the Sponsors and to certain wholesale customers of the Sponsors. The Parties agree that the eligibility for and certain aspects of the mechanics of those refunds and credits will be determined in accordance with the provisions of this Section 3.1.

3.1.1   Any customer with obligations and entitlements to purchase a specified percentage share of the power and energy produced by the Plant and to pay a like percentage of Vermont Yankee's costs pursuant to a contract with one or more Sponsors (or with an intermediary acting on behalf of one or more Sponsors) entered into on or before January 1, 1983, and whose obligations and entitlements relating to the Plant expire, by the terms of the contract in effect as of the date of this Agreement, on or before January 1, 2003, shall be eligible for credits pursuant to Section 3.2 and Section 4.2, provided the customer makes a timely election pursuant to Section 3.1.2.

3.1.2   Any customer eligible under Section 3.1.1 shall, within twenty (20) days of the submission of this Agreement to the Commission, notify Vermont Yankee in writing if it elects to receive the refunds and credits pursuant to Section 3.2 or Section 4.2, or both. Such notifications may be made on behalf of eligible customers by their legal or other representatives. Each customer making such a timely election is referred to herein as an "Electing Short-Term Purchaser" or "ESP."

3.1.3   The Sponsors and Vermont Yankee, as billing agent for certain Sponsors under their contracts with the ESPs, shall provide the credits provided for in Section 3.2 or Section 4.2 or both, in accordance with the election of each ESP, directly to the ESPs in accordance with those provisions. If an ESP is billed by another entity (other than Vermont Yankee) on behalf of one or more Sponsors, such Sponsors shall cause the billing entity to provide such ESP its appropriate share of the credit provided to the Sponsor by Vermont Yankee in Section 3.2 and/or Section 4.2, as applicable, in accordance with those provisions and the billing terms of the contract between the billing entity and the ESP. If an ESP is billed directly by an individual Sponsor, such Sponsor shall provide such ESP its appropriate share of the credit provided to the Sponsor by Vermont Yankee in Section 3.2 and/or Section 4.2, as applicable, in accordance with those provisions and the billing terms of the contract betw een the Sponsor and the ESP.

3.1.4   The election of an ESP under Section 3.1.2 shall be without prejudice to its assertion in any future proceeding of any claim against Vermont Yankee or any Sponsor, including without limitation a claim withdrawn without prejudice in accordance with Section 2.1.3(b), other than a claim for additional refunds, credits or other relief with respect to (i) the transaction costs associated with either the proposed Plant sale to AmerGen or a New Transaction, except as such claims are specifically preserved in Section 3.5 and/or arise from a violation of this Agreement, or (ii) decommissioning charges collected by Vermont Yankee or by any Sponsor from an ESP for the period prior to the effective date of superseding rates, except as such claims are specifically reserved in Section 4.3.3(a) and/or arise from a violation of this Agreement.

3.2       Vermont Yankee (or other entity billing an ESP on behalf of one or more Sponsors or an individual Sponsor pursuant to Section 3.1.3) will refund to the Sponsors and to the ESPs, as applicable, all amounts paid by ESPs with respect to transaction costs associated with the AmerGen transaction ("AmerGen Transaction Costs"). The total amount (the "Transaction Refund Amount") shall be determined pursuant to Section 3.3. Vermont Yankee (and, where possible, the other billing agents or individual Sponsors) will reflect the refunds in the first bills rendered under the Power Contracts and the Secondary Power Contracts after the Settlement Effective Date, as defined in Section 6.1, for all ESPs who have provided their notice(s) under Section 3.1.2 prior to Vermont Yankee's preparation of said bills. The refunds to the remaining ESPs (if any) shall be reflected on the next bills issued following their provision of the Section 3.1.2 notice. Vermont Yankee shall be aut horized to recover the Transaction Refund Amount in accordance with Section 3.4. Vermont Yankee's AmerGen Transaction Costs shall include:

3.2.1   Earnest money and/or other payments toward credit insurance; and

3.2.2   All other costs associated with the AmerGen transaction, including, without limitation, the costs of legal and other advisors and the time of Vermont Yankee personnel recorded in connection with the transaction.

A schedule showing the amount of AmerGen Transaction Costs incurred by Vermont Yankee through the date of this Agreement is attached to the Agreement as an Appendix.

3.3       The Transaction Refund Amount shall equal the sum of (a) the product of (i) the total amount of Vermont Yankee's AmerGen Transaction Costs, and (ii) the percentage ("Credit Percentage") equal to the total of the individual percentages of the power and energy from the Plant for which the ESPs are responsible, plus (b) interest on each portion thereof calculated in accordance with the Commission's regulations. Vermont Yankee shall allocate the Transaction Refund Amount to the Sponsors and the ESPs in proportion to the ESPs' respective shares of the Credit Percentage.

3.4       Except as provided in Section 6.1.1, Vermont Yankee shall recover the Transaction Refund Amount by amortizing it in equal monthly amounts over the remaining license life of the Plant, with carrying charges equal to Vermont Yankee's weighted average cost of capital, commencing with the first bills rendered under the Power Contracts after the Settlement Effective Date. Such amounts shall be payable under the Secondary Power Contracts in accordance with their terms.

3.5       Vermont Yankee will not treat transaction costs of the types described in Sections 3.2.1 and 3.2.2 associated with a new transaction involving the sale of the Plant ("New Transaction Costs" and "New Transaction," respectively) as an expense eligible for immediate recovery under the Power Contracts. Instead, Vermont Yankee will book and defer all such costs and recover them through amortization over the remaining license life of the Plant, with carrying charges equal to Vermont Yankee's weighted average cost of capital, starting with the first bills issued following the financial closing of a New Transaction. Other Parties agree that the manner and timing of recovery of New Transaction Costs provided in this Section are not subject to future challenge, but Parties other than Vermont Yankee reserve the right to challenge (a) whether particular costs fall within the definition of New Transaction Costs (provided that, upon a determination that a particular cost s hould not have been booked and deferred as a New Transaction Cost under this section, that cost may be promptly expensed if otherwise permitted under applicable contracts and FERC requirements); (b) whether particular costs that were expensed should have been booked and deferred as New Transaction Costs (provided that, upon a determination that such a cost should have been deferred, Vermont Yankee shall refund amounts collected with respect to that cost, with interest, and shall recover that cost pursuant to this Section); and/or (c) the prudence of Vermont Yankee's incurrence of particular New Transaction Costs. If a New Transaction does not close by July 1, 2004, Vermont Yankee may apply to the Commission for authorization to recover New Transaction Costs, provided that Vermont Yankee will bear the burden of justifying recovery of such costs and any party may take any position in response to such application, including opposing recovery in whole, or in part, on any basis.

Article IV

DECOMMISSIONING FUNDING

4.1       Reduction in Decommissioning Charges

4.1.1   Commencing with the Settlement Effective Date, Vermont Yankee's monthly charges for decommissioning will be reduced to one-twelfth of the annual level shown in Section 4.1.3. 4.1.2   The decommissioning charges established by Section 4.1.1 shall remain in effect from the Settlement Effective Date through the first to occur of:
(a) (b)	The financial closing of the New Transaction; or The date on which the Commission permits a revised schedule of decommissioning charges to take effect under section 205 or section 206 of the FPA, provided that no party shall propose an effective date for a revised schedule of decommissioning charges that is earlier than January 1, 2003, except as provided in Section 4.3.3.
4.1.3   The annual level of decommissioning charges (the "Settlement Decommissioning Level"), which shall be in effect for the period beginning with the Settlement Effective Date and ending in accordance with Section 4.1.2, shall be $11.4 million.

4.2       Treatment of ESPs' Decommissioning Charges

4.2.1   Vermont Yankee (or other entity billing an ESP on behalf of one or more Sponsors or an individual Sponsor pursuant to Section 3.1.3) shall provide to each appropriate Sponsor and to each ESP a credit (the "ESP Credit Amount") equal, for each ESP, to:
(a) (b) (c)	the difference over the period from January 1, 2000 through the day preceding the Settlement Effective Date between (1) the annual decommissioning collection level that was the basis for the ESP's decommissioning payments during the period, and (2) the Settlement Decommissioning Level; multiplied by the ESP's proportionate share of the Credit Percentage, plus interest calculated in accordance with Section 35.19a of the Commission's regulations.
4.2.2   Vermont Yankee (and, where possible, the other billing agents or individual Sponsors) will begin reflecting the ESP Credit Amounts on the first bills rendered under the Power Contracts and the Secondary Power Contracts after the Settlement Effective Date, as defined in Section 6.1, for all ESPs who have provided their notice(s) under Section 3.1.2 prior to Vermont Yankee's preparation of said bills. The ESP Credit Amounts for the remaining ESPs (if any) shall first be reflected on the next bills issued following their provision of the Section 3.1.2 notice. Each ESP shall receive its ESP Credit Amount as an offset to its decommissioning payment that would otherwise be due, up to the full amount payable by the ESP to the decommissioning trust funds for the month. Any remaining balance of an ESP's ESP Credit Amount shall be carried over, together with interest calculated in accordance with Section 35.19a of the Commission's regulations, and shall be applied as an offset to its decom missioning payment that would otherwise be due on subsequent monthly bills, provided that the credit in any month shall not exceed the total amount payable by the ESP in that month with respect to decommissioning. The process of carrying over (with interest) the remaining ESP Credit Amount, and applying the carried-over amounts as offsets, shall continue until the full amount of the ESP Credit Amount has been credited to the ESP. 4.2.3   If, as a result of a New Transaction or otherwise, the process of offsetting the ESPs' decommissioning payment obligations through the ESP Credit Amounts as contemplated under this Section 4.2 ends before the ESP Credit Amounts (including accrued interest) have been fully provided to the ESPs, Vermont Yankee shall make lump-sum refunds of all remaining ESP Credit Amounts (including accrued interest) to the appropriate Sponsors, which shall pass through the remaining ESP Credit Amounts (with interest) to the ESPs.

4.3       Superseding Decommissioning Charges

4.3.1   Any Party proposing a superseding schedule of decommissioning charges shall be free to base its proposal on any principles, subject to the Commission's approval, except:
(a) (b)	No proposal shall seek to adjust decommissioning charges collected for the period prior to the effective date of a new filing under section 205 or 206 of the FPA as permitted by Section 4.1.2(b), except as provided in Section 4.3.3; and The level of decommissioning charges specified in Section 4.1.3 shall not be precedential and shall not be cited as reflecting any party's view of an appropriate level of decommissioning charges.
4.3.2   If a New Transaction has not closed by July 1, 2004, and Vermont Yankee has not already made a rate filing with the Commission under section 205 (other than a filing limited in accordance with Commission policy to adjust accruals for post-retirement benefits expenses), then Vermont Yankee shall make a rate filing under section 205 of the FPA by September 1, 2004, which shall include any necessary adjustments to decommissioning charges to reflect Vermont Yankee's latest estimate of the costs of decommissioning the Plant, and other relevant factors, to take effect no later than January 1, 2005. Vermont Yankee shall not collect any charges for decommissioning other than charges based on the Settlement Decommissioning Level except pursuant to a superseding rate filing that is permitted to go into effect by the Commission. 4.3.3   Nothing in this Agreement shall prohibit:
(a) (b) (c)	any ESP from filing an application under section 206 of the Federal Power Act, 16 U.S.C. Section 824e, prior to December 1, 2002, seeking adjustment to, and/or refunds of, decommissioning charges paid under its contract with one or more Sponsors (including without limitation amounts paid, in cash or through application of credits, for decommissioning collections from and after January 1, 2000 in accordance with this Agreement), where said application is based on (i) the terms of a New Transaction or (ii) the fact (if it has transpired) that Vermont Yankee still owns the Plant and has applied to the Nuclear Regulatory Commission ("NRC") before December 31, 2002 to extend the term of the Plant's operating license beyond 2012; any Sponsor from filing an application under section 206 of the Federal Power Act, 16 U.S.C. Section 824e, prior to December 1, 2002, seeking additional decommissioning funding from any ESP, where said application is based on the fact (if it has transpired) that Vermont Yankee still owns the Plant and Vermont Yankee's Board of Directors has, before December 1, 2002, adopted a resolution to retire the Plant early; or any other Party from taking any position in response to any such application, if filed, including opposing any relief requested on any ground (other than a claim that the application is barred by the Agreement).

4.4.       In the event Vermont Yankee is required to borrow funds to bring the decommissioning trust funds to an agreed level in connection with a New Transaction, for any remaining portion of the period beginning with the Settlement Effective Date and ending on January 1, 2003, Vermont Yankee shall not impose monthly charges to recover amounts from Sponsors or ESPs with respect to repaying such borrowing that exceed the monthly charges for decommissioning that would have been paid under this Agreement but for the New Transaction. This section shall not restrict Vermont Yankee's ability to seek recovery of amounts relating to any other borrowing, including, if Vermont Yankee secures funds both to bring the decommissioning trust funds to an agreed level and for other purposes related to a New Transaction in a single borrowing, recovery of amounts relating to the portion of the borrowing associated with such other purposes.

4.5       Until the financial closing of a New Transaction or until otherwise ordered by FERC or agreed by any affected Party, Vermont Yankee shall provide the VDPS and any other Party that so requests with a quarterly report of decommissioning trust fund performance, including identification of book values, current market values, and after-tax values of each category of investments in the qualified and non-qualified funds, as reported to Vermont Yankee by the funds' managers.

Article V

MODIFICATION TO FORMULA RATE

5.1       Commencing with the Settlement Effective Date, Vermont Yankee shall modify the formula rate under the Power Contracts to eliminate the collection of amounts from the Sponsors to fund the Low-level Rad-waste Disposal Reserve created by the Commission's acceptance of the June 16, 1994, Settlement Agreement in Docket No. ER94-1370 in its order of September 2, 1994. The balance in the reserve will be applied to offset low-level rad-waste disposal costs. After the reserve is depleted, low-level rad-waste disposal costs that would formerly have been funded by the reserve will be recovered by Vermont Yankee as an operating expense when incurred, or, if incurred after decommissioning commences, as decommissioning expenses. Notwithstanding anything in the preceding sentence, the Parties other than Vermont Yankee reserve the right to raise issues with respect to (a) whether particular costs are appropriately considered low-level rad-waste disposal costs that would have formerly been funded by the reserve; and/or (b) the prudence of Vermont Yankee's incurrence of particular low-level rad-waste disposal costs.

Article VI

EFFECTIVE DATE AND OTHER TERMS AND CONDITIONS

6.1       This Agreement shall take effect on the date (the "Settlement Effective Date") determined as follows:

6.1.1   Concurrent with the submission of this Agreement to the Commission, the Parties shall jointly submit a motion asking FERC for permission to implement the credits and rate reductions as provided for in the Agreement on an interim basis as of June 1, 2001, if conditions specified in the motion are satisfied or, otherwise, the first day of the calendar month following Commission action on the motion. The motion shall provide for and be contingent upon the Commission's authorizing Vermont Yankee and the Sponsors to recoup the full amount of any credits and rate reductions so implemented, together with interest determined in accordance with Section 35.19a of the Commission's regulations, by adding the amount to their next monthly bills rendered under the Power Contracts and Secondary Power Contracts, following the issuance of a Commission order on review of the Agreement that fails to accept or approve the Agreement in its entirety. The Parties' aim and intention is to receive Commissi on approval of the joint motion such that the Settlement Effective Date will be June 1, 2001, if possible.

6.1.2   If the Commission denies the joint motion for interim implementation referred to in Section 6.1.1, the Settlement Effective Date shall be the date the Commission authorizes the Agreement to take effect. The Parties request a Settlement Effective Date of August 1, 2001 in that instance. If the Commission authorizes a Settlement Effective Date prior to the date of the Commission's order accepting or approving this Agreement, the credits and refunds provided shall be implemented by credits to the next bills rendered by Vermont Yankee and, as applicable, the Sponsors.

6.2       Unless specifically modified by this Agreement, the provisions of previous settlement agreements resolving wholesale rate proceedings filed by Vermont Yankee shall remain in effect.

6.3       The making of this Agreement shall not be deemed in any respect to constitute an admission by any party that any allegation or contention in this proceeding is true and valid.

6.4       The execution of this Agreement by any party and its acceptance or approval by the Commission shall not in any respect constitute a determination by the Commission as to the merits of any allegation or contentions made in these proceedings nor constitute approval of, or precedent regarding, any principle or issue in these proceedings. In particular, this Agreement shall not in any way be construed as establishing any precedent or policy. This Agreement shall not constitute precedent with respect to the appropriate level of funds necessary to decommission the Plant.

6.5       The discussions that have produced this Agreement have been conducted on the explicit understanding that they are subject to the protection of Rule 602(e) of the Commission's Rules of Practice and Procedure. All offers of settlement and discussions relating thereto are and shall be privileged, shall be without prejudice to the position of any party or participant presenting such offer or participating in any such discussions, and are not to be used in any manner in connection with these or other proceedings, except as may be necessary to enforce the terms of this Agreement. However, this paragraph shall not bar any Party's use in future proceedings of non-confidential factual information included in any Party's pleadings, testimony or other formal documents submitted in the course of the proceedings in Docket Nos. EC00-46 et al. and EL00-86.

6.6       This Agreement expressly is conditioned upon the Commission's final acceptance or approval of all provisions hereof without change or condition. In the event the Commission does not by order accept or approve the Agreement in its entirety, then, it shall be deemed withdrawn and shall not constitute any part of the record in these proceedings or be used for any other purpose and each of its provisions shall be deemed null and void.

6.7       Any number of counterparts of this Agreement may be executed. Each shall have the same force and effect as an original instrument, and as if all signatories to all the counterparts had signed the same instrument.

__________________________________ Kenneth G. Jaffe, Counsel On Behalf of Vermont Yankee Nuclear Power Corporation	__________________________________ Kathleen L. Mazure, Counsel Janice L. Lower, Counsel On Behalf of the Vermont Department of Public Service
__________________________________ Margaret A. McGoldrick, Counsel On Behalf of the Massachusetts Muncipals and CMEEC	__________________________________ Terry L. Schwennesen, Vice President, Generation Investments On Behalf of New England Power Company
__________________________________ Nancy Rowden Brock, Chief Financial Officer On Behalf of Green Mountain Power Company	__________________________________ Kent Brown, Senior Vice President, Engineering and Operations On Behalf of Central Vermont Public Service Corporation
__________________________________ Monique Rowtham-Kennedy, Counsel, On Behalf of The Connecticut Light and Power Company, Public Service Company of New Hampshire, and Western Massachusetts Electric Company	__________________________________ Robert Martin, On Behalf of Cambridge Electric Light Company
__________________________________ Robert S. Mahoney, Counsel, On Behalf of Central Maine Power Company	__________________________________ Heidi Werntz, Counsel, On Behalf of Vermont Electric Power Company