CENTRAL VERMONT PUBLIC SERVICE CORP, 10-Q, 2000-11-13

CENTRAL VERMONT PUBLIC SERVICE CORP
10-Q, 2000-11-13
ELECTRIC SERVICES

Previous: CENTRAL SECURITIES CORP, 13F-HR, 2000-11-13

Next: CENTURY REALTY TRUST, 10-Q, 2000-11-13

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2000

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

For the transition period from _______ to _______

Commission file number 1-8222

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

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

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

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

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

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. As of October 31, 2000 there were outstanding 11,507,980 shares of Common Stock, $6 Par Value.

Page 1 of 42

CENTRAL VERMONT PUBLIC SERVICE CORPORATION

Form 10-Q

Table of Contents

PART I.			FINANCIAL INFORMATION		PAGE

Item 1.		Financial Statements
	Consolidated Statement of Income and Retained Earnings for the three and nine months ended September 30, 2000 and 1999				3
	Consolidated Balance Sheet as of September 30, 2000 and December 31, 1999				4
	Consolidated Statement of Cash Flows for the nine months ended September 30, 2000 and 1999				5
	Notes to Consolidated Financial Statements				6-18
Item 2.		Management's Discussion and Analysis of Financial Condition and Results of Operations		19-40

PART II.			OTHER INFORMATION		41
SIGNATURE					42

Page 2 of 42

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
PART I. - FINANCIAL INFORMATION

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

	Three Months Ended		Nine Months Ended
	September 30		September 30
	2000	1999	2000			1999
Operating Revenues	$ 73,947	$ 113,221	$ 247,763			$ 305,002

Operating Expenses
Operation
Purchased Power	42,463	79,538	140,471			192,472
Production and transmission	6,319	5,996	19,634			16,756
Other Operation	10,785	12,932	31,647			36,166
Maintenance	4,074	5,660	10,307			12,700
Depreciation	4,179	4,308	12,685			12,705
Other taxes, principally property taxes	2,827	2,952	8,670			8,854
Taxes on income	347	77	6,755			7,872
Total operating expenses	70,994	111,463	230,169			287,525

Operating Income	2,953	1,758	17,594			17,477

Other Income and Deductions
Equity in earnings of affiliates	812	699	2,289			2,204
Other income net	8,075	146	6,661			1,436
Benefit (provision) for income taxes	(3,235)	4	(2,412)			(258)
Total other income and deductions, net	5,652	849	6,538			3,382

Total Operating and Other Income	8,605	2,607	24,132			20,859

Net Interest Expense	3,803	2,197	11,097			7,303

Net Income (Loss)	4,802	410	13,035			13,556

Retained Earnings at Beginning of Period	74,052	77,436	72,371			67,748
Retained Earnings before Dividends	78,854	77,846	85,406			81,304

Cash Dividends Declared
Preferred Stock	0	466	1,335			1,397
Common Stock	2,536	5,043	7,586			7,570
Total dividends declared	2,536	5,509	8,921			8,967

Other Adjustments	81	-	(86)			-

Retained Earnings at End of Period	$ 76,399	$ 72,337	$ 76,399			$ 72,337

Earnings (Losses) Available for Common Stock	$ 4,357	$ (56)	$ 11,700			$ 12,159

Average Shares of Common Stock Outstanding	11,502,433	11,463,019	11,482,006			11,462,196

Earnings (Losses) Per Basic and Diluted Share of Common Stock	$ .38	$ .00	$ 1.02			$ 1.06

Dividends Paid Per Share of Common Stock	$ .22	$ .22	$ .66			$ .66

The accompanying notes are an integral part of these consolidates financial statements. Page 3 of 42
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONSOLIDATED BALANCE SHEET
(Dollars in thousands)
				September 30			December 31
				2000			1999
Assets
Utility Plant, at original cost				$ 477,531			$ 475,845
Less accumulated depreciation				184,823			173,605
				292,708			302,240
Construction work in progress				16,976			11,315
Nuclear fuel, net				891			1,177
Net Utility Plant				310,575			314,732
Investments and Other Assets
Investments in affiliates, at equity				24,826			25,501
Non-utility investments				45,913			45,269
Non-utility property, less accumulated depreciation				2,243			2,513
Total investments and other assets				72,982			73,283
Current Assets
Cash and cash equivalents				60,868			35,461
Special deposits				116			113
Accounts receivable, less allowance for uncollectible accounts ($1,628 in 2000 and $1,595 in 1999)				23,861			38,381
Unbilled revenues				12,234			20,605
Materials and supplies				3,174			3,126
Prepayments				3,193			1,964
Other current assets				7,034			6,510
Total current assets				110,480			106,160
Regulatory Assets				45,800			62,808
Other Deferred Charges				6,702			6,976
Total Assets				$ 546,539			$ 563,959
Capitalization and Liabilities
Capitalization
Common stock, $6 par value, authorized 19,000,000 shares; outstanding 11,785,848 shares				$ 70,715			$ 70,715
Other paid-in capital				45,233			45,340
Accumulated other comprehensive income				(246)			(246)
Treasury stock (280,118 shares and 319,043 shares, respectively, at cost)				(3,654)			(4,159)
Retained earnings				76,399			72,371
Total common stock equity				188,447			184,021
Preferred and preference stock				7,054			8,054
Preferred stock with sinking fund requirements				17,000			17,000
Long-term debt				157,039			155,251
Capital lease obligations				14,249			15,060
Total capitalization				383,789			379,386
Current Liabilities
Current portion of long-term debt and preferred stock				17,691			16,688
Accounts payable				4,515			14,843
Accounts payable - affiliates				11,538			12,311
Accrued income taxes				10			675
Dividends declared				2,531			2,523
Nuclear decommissioning costs				2,226			3,457
Disallowed purchased power costs				2,859			2,859
Other current liabilities				18,623			18,823
Total current liabilities				59,993			72,179
Deferred Credits
Deferred income taxes				44,033			48,631
Deferred investment tax credit				6,147			6,440
Nuclear decommissioning costs				15,337			18,548
Other deferred credits				37,240			38,775
Total deferred credits				102,757			112,394
Total Capitalization and Liabilities				$ 546,539			$563,959
The accompanying notes are an integral part of these consolidated financial statements. Page 4 of 42
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in thousands)
(Unaudited)

					Nine Months Ended
					September 30
					2000			1999
Cash Flows Provided (Used) By Operating Activities
Net income					$ 13,035			$ 13,556
Adjustments to reconcile net income to net cash provided by operating activities
Equity in earnings of affiliates					(2,289)			(2,204)
Dividends received from affiliates					3,301			2,591
Equity in (earnings) losses of non-utility investments					198			(1,146)
Distribution of earnings from non-utility investments					3,040			2,906
Depreciation					12,685			12,705
Deferred income taxes and investment tax credits					(3,915)			2,884
Net deferral and amortization of nuclear refueling replacement energy and maintenance costs					4,707			1,575
Amortization of conservation and load management costs					4,004			5,080
Amortization of capital leases					817			811
Decrease in accounts receivable and unbilled revenues					22,194			3,461
Increase (decrease) in accounts payable					(10,281)			2,415
Decrease in accrued income taxes					(2,188)			(2,975)
Change in other working capital items					(350)			(8,102)
Other, net					3,285			(1,462)
Net cash provided by operating activities					48,243			32,095

Investing Activities
Construction and plant expenditures					(10,307)			(9,209)
Conservation & load management expenditures					(908)			(2,118)
Return of capital					267			140
Non-utility investments					(4,247)			(3,305)
Other investments, net					1			162
Net cash used for investing activities					(15,194)			(14,330)

Financing Activities
Short-term debt, net					2			(28,750)
Long-term debt, net					1,789			76,483
Common and preferred dividends paid					(8,912)			(8,496)
Reduction in capital lease obligations					(817)			(811)
Sale of common stock					505			25
Other					(209)			(5)
Net cash used for financing activities					(7,642)			38,446


Net Increase (Decrease) in Cash and Cash Equivalents					25,407			56,211
Cash and Cash Equivalents at Beginning of Period					35,461			10,051

Cash and Cash Equivalents at End of Period					$ 60,868			$ 66,262

Supplemental Cash Flow Information
Cash paid during the period for:
Interest (net of amounts capitalized)					$ 10,695			$ 5,490
Income taxes (net of refunds)					$ 14,951			$ 9,717

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

Page 5 of 42

CENTRAL VERMONT PUBLIC SERVICE CORPORATION

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 1999 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.

Note 2 - 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. These activities were discontinued by the Company 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.

Page 6 of 42

Cleveland Avenue Property The Company's Cleveland Avenue property, located in the City of Rutland, Vermont, was a site where one of its predecessors operated a coal-gasification facility and later the Company sited various operations functions. Due to the presence of coal tar deposits and Polychlorinated Biphenyl ("PCB") contamination and uncertainties as to potential off-site migration of those contaminants, the Company conducted studies in the late 1980's and early 1990's to determine the magnitude and extent of the contamination. After completing its preliminary investigation, the Company engaged a consultant to assist in evaluating clean-up methodologies and provide cost estimates. Those studies indicated the cost to remediate the site would be approximately $5.0 million. This was charged to expense in the fourth quarter of 1992. Site investigation has continued over the last several years and the Company continues to work with the State of Vermont in a joint effort to develop a mutually acceptable solution.

Brattleboro Manufactured Gas Facility From the early to late 1940's, the Company owned and operated a manufactured gas facility in Brattleboro, Vermont ("VT"). The Company received a letter from the State of New Hampshire ("NH") asking the Company to conduct a scoping study in and around the site of the former facility. The Company commissioned an environmental site assessment in late 1999. In April 2000, the Company presented the assessment findings to the states of NH and VT and the town of Brattleboro. The State of VT concluded that additional site monitoring is necessary and the Company must develop a Corrective Action Plan that includes a long-term groundwater monitoring program and implement institutional controls at the site to restrict access and exposure. The State of NH recently concluded that additional biological monitoring of the river sediment affected by site wastes is necessary. The State of NH requires this additional work to validate certain findings and conclusions made by the Company's consultant after completing its initial investigation in 1999. The Company expects to develop and submit responses to both the VT and NH agencies in 2000. At this time the Company has not finalized an estimate of its potential liability at this site.

Dover, New Hampshire Manufactured Gas Facility The Company was recently contacted by Public Service Company 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 is researching the underlying transactions and the transactions initially appear vague and complex regarding environmental liability. In view of this, the Company proposed, and PSNH tentatively accepted, an agreement that calls for an environmental mediator to assist in a non-binding evaluation of the Company's liability. The Company expects to start this mediation process in 2000. Concurrently, PSNH plans to submit a work plan to the State of NH for further investigation of this site. The Company agreed, with reservations, to participate in the development and completion of that work since the State of NH considers the Company potentially liable at the site. This work requires state review, comment and approval and will likely start in 2001. At this time, the Company has not finalized an estimate of its potential liability at this site.

The Company is not subject to any pending or threatened litigation with respect to any other sites that have the potential for causing the Company to incur material remediation expenses, nor

has the EPA or other federal or state agency sought contribution from the Company for the study or remediation of any such sites.

Page 7 of 42

As of September 30, 2000, a reserve of $9.6 million has been established representing management's best estimate of the costs to remediate the sites.

Note 3 - Retail Rates

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

Vermont Retail Rate Proceedings:

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

In response to the Company's September 1997 rate increase filing, the Vermont Public Service Board ("PSB") decided to appoint an independent investigator to examine the Company's decision to buy power from Hydro-Quebec. The Company made a filing with the PSB stating that the PSB as well as other parties should be barred from reviewing past decisions because the PSB already examined the Company's decision to buy power from Hydro-Quebec in a 1994 rate case in which the Company was penalized for "improvident power supply management". During February 1998, the Vermont Department of Public Service ("DPS") filed testimony in opposition to the Company's retail rate increase request. The DPS recommended that the PSB instead reduce the Company's then current retail rates by 2.5% or $5.7 million. The Company sought, and the PSB granted, permission to stay this rate case and to file an interlocutory appeal of the PSB's denial of the Company's motion to preclude a re-examination of the Company's Hydro-Quebec contract in 1991. The Company has argued its position before the Vermont Supreme Court ("VSC"). The VSC has not yet rendered a decision and it is uncertain at this time when a decision is forthcoming.

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

The 4.7% rate increase is subject to retroactive or prospective adjustment upon future resolution of issues arising under the Hydro-Quebec and Vermont Joint Owners ("VJO") Power Contract presently before the VSC. The agreement temporarily disallows approximately $7.4 million (based on 1999 power costs) for the Company's purchased power costs under the VJO

Power Contract pending resolution of the issues before the VSC. As a result of the 4.7% rate increase agreement, during the fourth quarters of 1998 and 1999, the Company recorded pre-tax

Page 8 of 42

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 the nine months ended September 30, 2000, an additional $8.6 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. If in the future, the Company is unable to increase rates to recover the temporary disallowed purchased power costs prior to further resolution under the VJO Power Contract or otherwise mitigate these costs, the Company would be required to record losses for any estimated future under recovery.

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

If the Company receives an unfavorable ruling from the VSC and the PSB subsequently issues a final rate order adopting the disallowance methodology used to determine the temporary Hydro-Quebec disallowance described above for the duration of the VJO Power Contract, the Company would not be able to recover approximately $198.2 million of power costs over the life of the contract, including $11.5 million in 2000, $11.6 million in 2001, $11.8 million in 2002, $11.9 million in 2003 and $12.1 million in 2004. In such an event, the Company would be required to take an immediate charge to earnings of approximately $198.2 million (pre-tax). Such an outcome could jeopardize the Company's ability to continue as a going concern. However, at this time, the Company does not believe that such a loss is probable.

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 will now have flat rates throughout a given year. Winter rates will be reduced by 14.9%, while summer rates will increase 10.5%. The rate design change will be revenue neutral over a 12-month period. The additional 2000 revenues, resulting from implementing this change in mid-year, will be applied to reduce or eliminate certain regulatory deferrals.

In an effort to mitigate eroding earnings and cash flow prospects in the future, due mainly to under recovery of power costs, on November 9, 2000, the Company filed with the PSB a request for a 7.6% rate increase ($19.0 million of annualized revenues) effective July 1, 2001.

New Hampshire Retail Rate/Federal Court Proceedings:

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

Page 9 of 42

On February 28, 1997 the NHPUC published its detailed Final Plan to restructure the electric utility industry in New Hampshire. Also on February 28, 1997, the NHPUC, in a supplemental order specific to Connecticut Valley, found that Connecticut Valley was imprudent for not terminating the FERC-authorized power contract between Connecticut Valley and the Company. The NHPUC required Connecticut Valley to give notice to cancel its contract with the Company and denied stranded cost recovery related to this power contract. Connecticut Valley filed for rehearing of the February 28, 1997 NHPUC Order.

On April 7, 1997, the NHPUC issued an Order addressing certain threshold procedural matters raised in motions for rehearing and/or clarification filed by various parties, including Connecticut Valley, relative to the Final Plan and interim stranded cost orders. The April 7, 1997 Order stayed those aspects of the Final Plan that were the subject of rehearing or clarification requests and also stayed the interim stranded cost orders for the various parties, including Connecticut Valley. As such, those matters pertaining to the power contract between Connecticut Valley and the Company were stayed. The suspension of these orders was to remain in effect until two weeks following the issuance of any order concerning outstanding requests for rehearing and clarification.

On November 26, 1997, Connecticut Valley filed a request with the NHPUC to increase FAC, PPCA and short-term energy purchase rates effective on or after January 1, 1998. The requested increase in rates resulted from higher forecast energy and capacity charges on power Connecticut Valley purchases from the Company plus removal of a credit effective during 1997 to refund over collections from 1996.

In an Order dated December 31, 1997 in Connecticut Valley's FAC and PPCA docket, the NHPUC found Connecticut Valley acted imprudently by not terminating the wholesale contract between Connecticut Valley and the Company, notwithstanding the stays of its February 28, 1997 Orders. The NHPUC Order further directed Connecticut Valley to freeze its current FAC and PPCA rates (other than short term rates to be paid to certain Qualifying Facilities) effective January 1, 1998, on a temporary basis, pending a hearing to determine: 1) the appropriate proxy for a market price that Connecticut Valley could have obtained if it had terminated its wholesale contract with the Company; 2) the implications of allowing Connecticut Valley to pass on to its customers only that market price; and 3) whether the NHPUC's final determination on the FAC and PPCA rates should be reconciled back to January 1, 1998 or some other date.

On January 19, 1998, Connecticut Valley and the Company filed with the Federal District Court ("Court") for a Temporary Restraining Order ("TRO") to maintain the status quo ante by staying the NHPUC Order of December 31, 1997 and preventing the NHPUC from taking any action that (i) compromises cost-based rate making for Connecticut Valley; (ii) interferes with FERC's exclusive jurisdiction over the Company's pending application to recover wholesale stranded costs upon termination of its wholesale power contract with Connecticut Valley; or (iii) prevents Connecticut Valley from recovering through retail rates the stranded costs and purchased power costs that it incurs pursuant to its FERC-authorized wholesale rate schedule with the Company.

On February 23, 1998, the NHPUC announced in a public meeting that it reaffirmed its finding of imprudence and designated a proxy market price for power at 4 cents per kWh in lieu of the actual costs incurred pursuant to the wholesale power contract with the Company. In addition, the NHPUC indicated, subject to certain conditions which were unacceptable to the

Page 10 of 42

companies, that it would permit Connecticut Valley to maintain its current rates pending a decision in Connecticut Valley's appeal of the NHPUC Order to the New Hampshire Supreme Court.

Based on the December 31, 1997 NHPUC Order as well as the NHPUC's February 23, 1998 announcement, which resulted in the establishment of Connecticut Valley's rates on a non cost-of-service basis, Connecticut Valley no longer qualified, as of December 31, 1997, for the application of Statement of Financial Accounting Standards No. 71 ("SFAS No. 71"). As a result, Connecticut Valley wrote-off all of its regulatory assets associated with its New Hampshire retail business as of December 31, 1997. This write-off amounted to approximately $1.2 min on a prmatre-tax basis. In addition, Connecticut Valley recorded a $5.5 million pre-tax loss in 1997 for disallowed power costs.

On March 20, 1998, the NHPUC issued an order which affirmed, clarified and modified various generic policy statements including the reaffirmation to establish rates on the basis of a regional average announced previously in its February 28, 1997 Order. The March 20, 1998 Order also addressed all outstanding motions for rehearings or clarification relative to the policies or legal positions articulated in the Final Plan and removed the stay covering the Company's interim stranded cost order of April 7, 1997. In addition, the March 20, 1998 Order imposed various compliance filing requirements.

On April 3, 1998, the Court held a hearing on the Companies' motion for a TRO and Preliminary Injunction against the NHPUC at which time both the companies and the NHPUC presented arguments. In an oral ruling from the bench, and in a written order issued on April 9, 1998, the Court concluded that the companies had established each of the prerequisites for preliminary injunctive relief and directed and required the NHPUC to allow Connecticut Valley to recover through retail rates all costs for wholesale power that Connecticut Valley purchases from the Company pursuant to its FERC-authorized wholesale rate schedule effective January 1, 1998 until further court order. Connecticut Valley received an order from the NHPUC authorizing retail rates to recover such costs beginning in May 1998. On April 14, 1998, the NHPUC filed a notice of appeal and a motion for a stay of the Court's preliminary injunction. The NHPUC's request for a stay was denied. At the same time, the NHPUC permitted Connecticut Valley to recover in rates the full cost of its wholesale power purchases from the Company.

Also, on April 3, 1998, the Court indicated its earlier TRO enjoining the NHPUC's restructuring orders applied to Connecticut Valley which prohibits the enforcement of the restructuring orders until the Court conducts a consolidated hearing and rules on the requests for permanent injunctive relief by plaintiff PSNH and the other utilities that had been allowed to intervene in these proceedings, including the Company and Connecticut Valley. The plaintiffs-interveners thereafter filed a motion asking the Court to extend its stay of action by the NHPUC to implement restructuring and to make clear that the stay encompasses the NHPUC's order of March 20, 1998.

As a result of these Court orders, Connecticut Valley's 1997 charges, described above, were reversed in the first quarter of 1998. Combined, the reversal of these charges increased 1998 net income and earnings per share of common stock by approximately $4.5 million and $.39, respectively.

Page 11 of 42

On April 1, 1998, Citizens Bank of New Hampshire ("Bank") notified Connecticut Valley

that it was in default of the Loan Agreement between the Bank and Connecticut Valley dated December 27, 1994 and that the Bank would exercise all of its remedies from and after May 5, 1998 in the event that the violations were not cured. After reversing the 1997 write-offs described above, Connecticut Valley was in compliance with the financial covenants associated with its $3.75 million loan with the Bank. As a result, Connecticut Valley satisfied the Bank's requirements for curing the violation.

On May 11, 1998, the NHPUC issued an order requiring Connecticut Valley to show cause why it should not be held in contempt for its failure to meet the compliance filing requirements of its March 20, 1998 Order. A hearing on this matter was scheduled for June 11, 1998, which was subsequently canceled because of the Court's June 5, 1998 Order, discussed below.

On June 5, 1998, the Court issued an Order which denied the NHPUC's motion for a stay of the Court's preliminary injunction. The Order clearly stated that no restructuring effort in New Hampshire can move forward without the Court's approval unless all New Hampshire utilities agree to the plan. The Order suspended all involuntary restructuring efforts for all New Hampshire utilities until a hearing on the merits was conducted. The NHPUC appealed this Order to the Court of Appeals.

On July 23, 1998, the NHPUC issued an order vacating that portion of its February 27, 1997 restructuring order that had directed Connecticut Valley to terminate its RS-2 wholesale power purchases from the Company. The NHPUC has expressly stated in federal court filings that its July 23, 1998 order "clarified that Connecticut Valley should not terminate the RS-2 Rate Schedule if such termination would trigger the exit fee" for which the Company has sought authorization from FERC.

On November 24, 1998, Connecticut Valley filed with the NHPUC its annual FAC/PPCA rates to be effective January 1, 1999. On January 4, 1999, the NHPUC issued an Order allowing Connecticut Valley to implement the proposed FAC and PPCA rates, on a temporary basis, effective on all bills rendered on or after January 1, 1999. In addition, the NHPUC also ordered Connecticut Valley to pay refunds plus interest to its retail customers for any overcharges collected as a result of the April 9, 1998 Federal District Court Order, should it be overturned or modified, which are included in the estimated total losses of $4.3 million discussed below.

On December 3, 1998, the Court of Appeals announced its decisions on the appeals taken by the NHPUC from the preliminary injunctions issued by the Court. Those preliminary injunctions had stayed implementation of the NHPUC's plan to restructure the New Hampshire electric industry and required the NHPUC to allow Connecticut Valley to recover through its retail rates the full cost of wholesale power obtained from the Company.

The Court of Appeals affirmed the preliminary injunction, issued by the Court, staying restructuring until the plaintiff utilities' claims (including those of the Company and Connecticut Valley) are fully tried. The Court of Appeals found that PSNH had sufficiently established that, without the preliminary injunction against restructuring, it would suffer substantial irreparable injury and that it had sufficient claims against restructuring to warrant a full trial. The Court of Appeals also affirmed the extension of the preliminary injunction to protect the other plaintiff utilities, including Connecticut Valley and the Company, although it questioned whether the other utilities had arguments as strong against restructuring as PSNH because they did not have

Page 12 of 42

formal agreements with the State similar to PSNH's Rate Agreement. The Court of Appeals

stated that if the Court awards the utilities permanent injunctive relief against restructuring after the case is tried, then it must explain why the other utilities are also entitled to such relief. The NHPUC filed a petition for rehearing on December 17, 1998. The Court of Appeals denied the petition on January 13, 1999.

The Court of Appeals also reversed the Court's preliminary injunction requiring the NHPUC to allow Connecticut Valley to recover in retail rates the full cost of the power it buys from the Company. Although the Court of Appeals found that Connecticut Valley and the Company had made a strong showing of irreparable injury to justify the preliminary injunction, it concluded that Connecticut Valley's and the Company's claims did not have a sufficient probability of success to warrant such preliminary relief. The Court of Appeals explained that the filed-rate doctrine preserving the exclusive jurisdiction of the FERC over wholesale power rates did not prevent the NHPUC from deciding whether Connecticut Valley's power purchases from the Company were prudent given alternative available sources of wholesale power. The Court of Appeals then stated that Connecticut Valley's rates could be reduced to the level prevailing on December 31, 1997. However, the Court of Appeals also stated that if the NHPUC ordered Connecticut Valley's rates to be reduced below the level existing as of December 31, 1997, "it will be time enough to consider whether they are precluded from the Court's injunction against the Final Plan or on other grounds."

On December 17, 1998, Connecticut Valley and the Company filed a petition for rehearing on the grounds that the Court of Appeals had not given sufficient weight to the Court's factual findings and that the Court of Appeals had misapprehended both factual and legal issues. Connecticut Valley and the Company also asked that the entire Court of Appeals, rather than only the three-judge appellate panel that had issued the December 3 decision, consider their petition for rehearing. On January 13, 1999, the Court of Appeals denied the petition for rehearing.

Connecticut Valley and the Company then requested the Court of Appeals to stay the issuance of its mandate until the companies could file a petition of certiorari to the United States Supreme Court and the Supreme Court acted on the petition.

On January 22, 1999, the Court of Appeals denied the request. However, the Court of Appeals granted a 21-day stay to enable the Company to seek a stay pending certiorari from the Circuit Justice of the Supreme Court. On February 11, 1999, the Company and Connecticut Valley filed a petition for a writ of certiorari with the United States Supreme Court and a motion to stay the effect of the Court of Appeals' decision while the case was pending in the Supreme Court. The motion for a stay was addressed to Justice Souter who is responsible for such motions pertaining to the Court of Appeals for the First Circuit. On February 18, 1999, Justice Souter denied the stay pending the petition for certiorari. On April 19, 1999, the Supreme Court denied the petition for certiorari.

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 within five business days 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. In its Order, 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

Page 13 of 42

collection relative to the 1997 rate level. The Company estimated this amount to be approximately $2.7 million on a pre-tax basis. Connecticut Valley filed the required tariff page

with the NHPUC, under protest and with reservation of all rights, on March 26, 1999, and implemented the refund effective April 1, 1999.

As a result of legal and regulatory actions discussed above, Connecticut Valley no longer qualified as of December 31, 1998 for the application of SFAS No. 71, and wrote-off in the fourth quarter of 1998 all of its regulatory assets associated with its New Hampshire retail business estimated at approximately $1.3 million on a pre-tax basis at December 31, 1998. In addition, Connecticut Valley recorded estimated total losses of $4.3 million pre-tax during the fourth quarter of 1998 for disallowed power costs of $1.6 million and its refund obligations of $2.7 million.

The pre-tax losses described above resulted in Connecticut Valley violating applicable covenants, which if not waived or renegotiated, would have allowed Connecticut Valley's lender the right to accelerate the repayment of a $3.75 million loan with Connecticut Valley. On March 12, 1999, Connecticut Valley was notified by the Bank that it would exercise appropriate remedies in connection with the violation of financial covenants associated with the $3.75 million loan agreement unless the violation was cured by April 11, 1999. To avoid default of this loan agreement, on April 6, 1999, pursuant to an agreement reached on March 26, 1999, the Company purchased from the Bank the $3.75 million note.

On April 7, 1999, the 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. Lastly, the Court denied the NHPUC's motion to dissolve the injunction staying the implementation of its restructuring plan and stated its desire to rule on the pending motion for summary judgement and to conduct a hearing on the Company's request for a permanent injunction, after the NHPUC completes hearings on PSNH's stranded costs. The District Court's decision was issued as a written order on May 11, 1999.

The NHPUC held a hearing on April 22, 1999 to determine whether to modify Connecticut Valley's 1999 power rates by returning the rates to the levels that were in effect on December 31, 1997. 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 contend, among other things, that it is unfair for the NHPUC to direct Connecticut Valley to continue to purchase wholesale power under RS-2 in order to avoid the triggering of a FERC exit fee, but at the same time to freeze Connecticut Valley's rates at their December 31, 1997 level which does not enable Connecticut Valley to recover all of its RS-2 costs.

Page 14 of 42

On June 14, 1999, PSNH and various parties in New Hampshire announced that a "Memorandum of Understanding" had been reached that is 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 indefinitely while the proposed settlement is reviewed and approved by the NHPUC and the New Hampshire Legislature. On July 12, 1999, the Company and Connecticut Valley objected to any stay that would allow the NHPUC's rate freeze order to remain in effect for an extended period and asked the Court to proceed with prompt hearings on its summary judgement motion and trial on the merits. On October 20, 1999, the Court heard oral arguments pertaining to the pretrial motions of the Company and the NHPUC for summary judgement and dismissal, respectively.

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

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

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

On March 6, 2000, the Court granted summary judgment 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 RS-2 rate schedule with the Company. The Court also ruled that Connecticut Valley is entitled to recover those wholesale costs that the NHPUC has disallowed in retail rates since January 1, 1997. This decision is subject to implementation by the NHPUC and has been appealed by the NHPUC to the Court of Appeals. The NHPUC also requested the Court of Appeals to stay the Court's order pending the Court's review on appeal. In response, Connecticut Valley offered to place the additional revenues in escrow pending the outcome of appeal. The Court of Appeals denied the NHPUC's request for a stay so long as the incremental revenues were placed in escrow.

Pursuant to the March 6, 2000 Court's Order, on March 17, 2000 Connecticut Valley filed a rate request with the NHPUC for an Interim FAC/PPCA to recover the balance of wholesale costs not recovered since January 1997. To mitigate the rate increase percentage, the Interim FAC/PPCA were designed to recover current power costs and a substantial portion of past under collections by the end of 2000; the remainder of the past under collections will be collected

Page 15 of 42

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. The Order is still subject to a possible appeal to the United States Supreme Court. As a result of the favorable Court of Appeals action, Connecticut Valley recorded an after-tax gain in the third quarter of $2.0 million.

Wheelabrator: 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 1999, under long-term contracts with these qualifying facilities, Connecticut Valley purchased 40,145 mWh, of which 37,309 mWh were 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 of 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 substantially the same relief that was requested of FERC.

Federal Energy Regulatory Commission ("FERC") Proceedings: The Company filed an application with the FERC in June 1997, to recover stranded costs in connection with its wholesale rate schedule with Connecticut Valley and a notice of cancellation of the Connecticut Valley rate schedule (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 our 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 contract with Connecticut Valley. The stranded cost obligation sought to be recovered through an exit fee, expressed on a net present value basis as of January 1, 2000, is approximately $44.9 million. On September 14 and 15, 1998 the Company participated in a settlement conference with an Administrative Law Judge assigned for the settlement process at the FERC and the parties to the Company's exit fee filing. During April and May 1999, nine days of hearings were held at the FERC before an Administrative Law Judge, who will determine, among other things, whether Connecticut Valley qualifies for an exit fee, and if so, the amount of Connecticut Valley's stranded cost obligation to be paid to the Company as an exit fee. The ruling of the Administrative Law Judge could be issued at any time. Thereafter the FERC will act on the judge's recommendations.

If the Company is unable to obtain an order authorizing the recovery of costs in connection with the June 1997 FERC filing or in the Federal Court, it is possible that the Company would be required to recognize a pre-tax loss under this contract totaling approximately $56.3 million as of December 31, 1999. The Company would also be required to write-off approximately $3.0 million (pre-tax) in regulatory assets associated with its wholesale business as of December 31 ,

Page 16 of 42

1999. If the Company obtains a FERC order authorizing the requested exit fee, Connecticut Valley will have to apply to the NHPUC to increase rates in order to pay the exit fee. The Company believes that the NHPUC must permit Connecticut Valley to raise rates to recover the cost of the exit fee. However, if Connecticut Valley is unable to recover its costs by increasing its rates, Connecticut Valley would be required to recognize a loss under this contract of

approximately $44.9 million (pre-tax) representing future under recovery of power costs as of December 31, 1999.

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

An adverse resolution of these 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.

Note 4 - Segment Reporting

Operating segments are defined as components of an enterprise about which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision making group, in deciding how to allocate resources and in assessing performance. The Company's chief operating decision making group is the Board of Directors, which is comprised of nine Directors including the Chairman of the Board and the Company's President and Chief Executive Officer. The operating segments are managed separately because each operating segment represents a different retail rate jurisdiction or offers different products or services.

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 which pursues retail alliances to market energy and related products and services, engages in the sale of or rental of electric water heaters and currently has a 31.3% ownership interest in The Home Service Store, Inc. ("HSS"). CVEC, while managed on an integrated basis with CV, is presented separately because of its separate and distinct regulatory jurisdiction. Other operating segments include a segment below the quantitative threshold for separate disclosure. This operating segment is C. V. Realty, Inc., a real estate company whose purpose is to own, acquire, buy, sell and lease certain real and personal property and interests therein related to the utility business. Segment information for the third quarter of 1999 has been restated to separately present SmartEnergy which became a reportable segment during the fourth quarter of 1999.

The accounting policies of the operating segments are the same as those described in Note 1

to Consolidated Financial Statements included in its 1999 Annual Report on Form 10-K filed with the Securities and Exchange Commission. Intersegment revenues include sales of purchased power to Connecticut Valley and revenues for support services to Connecticut Valley, Catamount and SmartEnergy.

Page 17 of 42

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

Financial information by industry segment for the three and nine months ended September 30, 2000 and 1999, is as follows (dollars in thousands):

Three Months Ended September 30, 2000	CV Vermont	CVEC New Hampshire	Catamount	SmartEnergy	Other (1)	Reclassifications & Consolidating Entries	Consolidated
Revenues from external customers	$ 65,573	$ 8,377	$ 145	$ 645	-	$ (793)	$ 73,947
Intersegment revenues	2,946	-	-	-	-	(2,946)	-
Net Income (loss)	2,043	2,323	492	(60)	$ 4	-	4,802
Total Assets	$ 485,544	$ 12,283	$ 47,701	$ 5,641	$ 312	$ (4,942)	$ 546,539
1999
Revenues from external customers	$ 108,813	$ 4,408	$ 140	$ 1,097	$ -	$ (1,237)	$ 113,221
Intersegment revenues	2,858	-	-	-	-	(2,858)	-
Net Income (loss)	459	159	334	(441)	(101)	-	410
Total Assets	$ 520,374	$ 12,247	$ 41,298	$ 6,741	$ 2,366	$ (6,372)	$ 576,654
(1) Includes segments below the quantitative threshold for separate disclosure.

Nine Months Ended September 30, 2000	CV Vermont	CVEC New Hampshire	Catamount	SmartEnergy	Other (1)	Reclassifications & Consolidating Entries	Consolidated
Revenues from external customers	$ 229,743	$ 18,026	$ 370	$ 2,300	-	$ (2,676)	$ 247,763
Intersegment revenues	9,403	-	-	-	-	(9,403)	-
Net Income (loss)	12,469	2,169	789	(2,402)	10	-	13,035
Total Assets	$ 485,544	$ 12,283	$ 47,701	$ 5,641	$ 312	$ (4,942)	$ 546,539
1999
Revenues from external customers	$ 289,293	$ 15,710	$ 436	$ 5,383	$ -	$ (5,820)	$ 305,002
Intersegment revenues	9,313	-	-	-	-	(9,313)	-
Net Income (loss)	12,558	483	1,247	(995)	263	-	13,556
Total Assets	$ 520,374	$ 12,247	$ 41,298	$ 6,741	$ 2,366	$ (6,372)	$ 576,654
(1) Includes segments below the quantitative threshold for separate disclosure.

Note 5 - Investment in Vermont Yankee Nuclear Power Corporation

The Company accounts for its investment in Vermont Yankee using the equity method. Summarized financial information for Vermont Yankee Nuclear Power Corporation follows:

	Three Months Ended		Nine Months Ended
	September 30		September 30
	2000	1999	2000	1999
Operating revenues	$44,648	$49,029	$130,042	$131,182
Operating income	$ ,263	$ 3,651	$ 12,173	$ 11,044
Net income	$ 1,560	$ 1,580	$ 4,942	$ 4,874
Company's equity in net income	$ 481	$ 463	$ 1,541	$ 1,504

Page 18 of 42

CENTRAL VERMONT PUBLIC SERVICE CORPORATION

Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Earnings Overview

The Company recorded net income, including non-recurring gains, of $4.8 million, or $.38 per share of common stock for the quarter ended September 30, 2000 compared to net income of $.4 million, or $.00 per share of common stock, for the corresponding period last year.

Higher third quarter 2000 earnings compared to last year resulted mainly from nonrecurring gains related to a favorable Millstone Unit #3 settlement and a favorable Connecticut Valley Electric Company ("CVEC") First Circuit Court of Appeals decision amounting to $3.2 million after-tax, or $.28 per share of common stock, and $2.0 million after-tax, or $.18 per share of common stock, respectively, and lower operating and other costs of $2.4 million after-tax, or $.21 per share of common stock, primarily due to lower distribution costs. In addition, SmartEnergy Services, Inc., had lower net losses of $.4 million after tax, or $.04 per share of common stock. This was offset by net expenses booked of $1.7 million after-tax, or $.15 per share of common stock, for expected under recovery of power costs to be incurred on the Hydro-Quebec ("HQ") power contract during the fourth quarter of 2000. In addition, utility revenues were lower by $2.2 million after-tax or $.19 per share of common stock, primarily resulting from a decrease in retail prices and a 3.54% (20,632 mWh) decrease in retail mWh sales.

For the nine months ended September 30, 2000, the Company had net income, including nonrecurring gains, of $13.0 million, or $1.02 per share of common stock, compared to net income of $13.6 million or $1.06 per share of common stock, for the nine months of 1999.

Lower nine months ended September 30, 2000 earnings compared to last year resulted primarily from expenses booked of $5.0 million after-tax, or $.45 per share of common stock, for expected under recovery of power costs on the HQ power contract during the second, third and fourth quarters of 2000. Lower utility revenues and higher net power costs were $1.0 million after-tax, or $.09 per share of common stock, and $.8 million after-tax, or $.07 per share of common stock, respectively. Increased net losses at SmartEnergy Services, Inc. (incurred in the first quarter of 2000) compared to last year were $1.4 million after-tax, or $.12 per share of common stock. This was offset by nonrecurring gains related to a favorable Millstone Unit #3 settlement and a favorable CVEC First Circuit Court of Appeals decision of $3.2 million after-tax, or $.28 per share of common stock and $2.0 million after-tax, or $.14 per share of common stock, respectively, and lower operating and other costs were $3.0 million after-tax, or $.31 per share of common stock, primarily due to lower distribution costs.

Other factors affecting results for 2000 are described in Results of Operations below.

RESULTS OF OPERATIONS

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

Page 19 of 42

Operating Revenues and mWh Sales

A summary of mWh sales and operating revenues for the three and nine months ended September 30, 2000 and 1999 (and the related percentage changes from 1999) is set forth below:

	Three Months Ended September 30
			Percentage			Percentage
	MWh Sales		Increase	Revenues (000's)		Increase
	2000	1999	(Decrease)	2000	1999	(Decrease)
Retail sales:
Residential	217,652	225,927	(3.7)	$ 25,365	$ 26,907	(5.7)
Commercial	236,975	246,269	(3.8)	23,912	25,625	(6.7)
Industrial	106,374	109,445	(2.8)	7,808	7,739	0.9
Other retail	1,587	1,579	0.5	450	454	(0.9)
Total retail sales	562,588	583,220	(3.5)	$ 57,535	$ 60,725	(5.3)
Resale sales:
Firm	329	307	7.2	$ 33	$ 37	(10.8)
Entitlement	108,490	53,115	104.3	3,690	2,357	56.6
Alliance	80,000	1,103,173	(92.7)	2,837	40,881	(93.1)
Other	134,426	50,424	166.6	5,274	4,559	15.7
Total resale sales	323,245	1,207,019	(73.2)	$ 11,834	$ 47,834	(75.3)
Other revenue	-	-	-	$ 4,578	$ 2,001	128.8
Total sales	885,833	1,790,239	(50.5)	$ 73,947	$ 110,560	(33.1)

	Nine Months Ended September 30
			Percentage			Percentage
	MWh Sales		Increase	Revenues (000's)		Increase
	2000	1999	(Decrease)	2000	1999	(Decrease)
Retail sales:
Residential	712,819	712,872	0.0	$ 90,333	$ 90,759	(0.5)
Commercial	689,466	709,703	(2.9)	76,268	79,653	(4.2)
Industrial	342,031	322,238	6.1	27,574	26,317	4.8
Other retail	4,725	4,688	0.8	1,339	1,343	(0.3)
Total retail sales	1,749,041	1,749,501	0.0	$ 195,514	$ 198,072	(1.3)
Resale sales:
Firm	1,431	1,653	(13.4)	$ 103	$ 116	(11.2)
Entitlement	243,468	161,697	50.6	8,444	7,494	12.7
Alliance	530,800	2,118,915	(74.9)	19,347	76,882	(74.8)
Other	496,361	523,267	( 5.1)	16,880	10,815	56.1

Total resale sales	1,272,060	2,805,532	(54.7)	$ 44,774	$ 95,307	(53.0)
Other revenue	-	-	-	$ 7,475	$ 4,153	80.0
Total sales	3,021,101	4,555,033	(33.7)	$ 247,763	$ 297,532	(16.7)

Retail mWh sales for the third quarter of 2000 decreased 3.5% compared to the third quarter of 1999 and retail revenues decreased $3.2 million, or 5.3% compared to last year. This retail revenue variance is attributable to a $2.2 million impact of lower mWh sales in the third quarter of 2000 as compared to the third quarter of 1999 and a $1.0 million decrease in price, primarily due to the rate reduction for the funding of the State of Vermont sponsored Energy Efficiency Utility ("EEU").

For the nine months of 2000, retail revenues decreased 1.3% compared to the nine months of 1999, attributable to the rate reduction for funding the EEU. These reduced revenues were offset by reduced amortization of C&LM expenses in other operating expenses.

Effective January 1, 2000 power purchased from Hydro-Quebec is recorded net of

Page 20 of 42

entitlement sales to Hydro-Quebec. The 1999 entitlement sales included in Resale sales has been restated for comparison purposes, along with Purchased and Produced Energy (mWh) shown in the table below.

Alliance resale sales decreased 1,023,173 mWh and 1,588,115 mWh for the third quarter and nine months of 2000, respectively, and related revenues decreased $38.0 million and $57.5 million for those same periods, respectively. This decrease resulted from reduced activity by the Company through its alliance with Virginia Power in jointly supplying wholesale power primarily in the Northeast states. In the third quarter of 1999 the Company decided to discontinue this alliance.

For the third quarter and nine months of 2000, other resale sales increased 84,002 mWh and decreased 26,906 mWh and related revenues increased $.7 million and $6.1 million, respectively. These variances reflect current market conditions in Vermont and New England. These sales made on a short-term basis, include sales to ISO New England ("ISO-NE") and other utilities in New England.

Other revenues increased $2.6 million and $3.3 million for the third quarter and nine months of 2000 primarily due to a non-recurring gain for the reversal of the provision for rate refunds ($3.2 million and $2.6 million for the third quarter and nine months of 2000, respectively) related to a favorable First Circuit Court of Appeals decision allowing CVEC to recover all of its power costs in rates.

Net Purchased Power and Production Fuel Costs

The net cost components of purchased power and production fuel costs for the three and nine months ended September 30, 2000 and 1999 are as follows (dollars in thousands):

	Three Months Ended September 30
	2000		1999
	Units	Amount	Units	Amount
Purchased and produced:
Capacity (mW)	400	$ 23,102	734	$ 20,397
Energy (mWh)	839,551	19,361	1,753,132	56,482
Total purchased power costs		$ 42,463		$ 76,879
Production fuel (mWh)	94,996	1,292	87,035	1,208
Total purchased power and production fuel costs		$ 43,755		$ 78,087
Entitlement and other resale sales (mWh)	322,916	11,801	1,206,712	47,797
Net purchased power and production fuel costs	611,631	$ 31,954	633,455	$ 30,290

	Nine Months Ended September 30
	2000		1999
	Units	Amount	Units	Amount
Purchased and produced:
Capacity (mW)	421	$ 69,949	856	$ 62,364
Energy (mWh)	2,829,054	70,522	4,425,076	122,638
Total purchased power costs		$140,471		$185,002
Production fuel (mWh)	346,257	3,347	292,651	2,554
Total purchased power and production fuel costs		$143,818		$187,556
Entitlement and other resale sales (mWh)	1,270,629	44,671	2,803,879	95,191
Net purchased power and production fuel costs	1,904,682	$ 99,147	1,913,848	$ 92,365

Page 21 of 42

Purchased and produced capacity (mW) costs increased $2.7 million pre-tax for the third quarter of 2000 versus 1999, primarily due to a $2.9 million pre-tax loss accrual for the estimated future under recovery of Hydro-Quebec power costs for the fourth quarter of 2000 and $1.6

million pre-tax increase in capacity costs related to the VJO contract. This increase is offset by the positive impact of $1.0 million pre-tax for Hydro-Quebec power cost reversals, representing the reversal of a portion of disallowed Hydro-Quebec power costs accrued during the fourth quarter of 1998, and the second quarter of 2000.

Purchased and produced energy (mWh) purchases decreased $37.1 million for the third quarter of 2000 compared to the third quarter of 1999, primarily due to a 92%, or $37.9 million decrease in the amount of mWh purchased related to reduced activity with Virginia Power.

For the nine months of 2000, net purchased power and production fuel costs increased $6.8 million pre-tax or 7.3% compared to the nine months of 1999 due to $8.6 million in pre-tax loss accruals for the estimated future under recovery of Hydro-Quebec power costs booked in 2000 and a $4.9 million pre-tax increase in capacity costs related to the VJO contract. The increased net purchased power and production fuel costs are partially offset by the positive impact of $3.1 million pre-tax for Hydro Quebec power cost reversals, representing the reversal of a portion of disallowed Hydro-Quebec power costs accrued during the fourth quarter of 1998 and 1999, and the first and second quarters of 2000, and $4.5 million pre-tax related to net purchases and sales to ISO-NE.

NUCLEAR MATTERS

The Company maintains a 1.7303% joint-ownership interest in the Millstone Unit #3 ("Unit #3"), a 1,149 mW nuclear unit of the Millstone Nuclear Power Station and owns a 2% equity interest in Connecticut Yankee. These two plants are operated by Northeast Utilities ("NU"). The Company also owns 2%, 3.5% and 31.3% equity interest in Maine Yankee, Yankee Atomic and Vermont Yankee, respectively.

Millstone Unit #3

On September 15, 1999, 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. Pursuant to the terms of the settlement agreement with NU which resolved the Company's claims against NU relating to the extended outage of Unit #3, the Company participated as a potential seller in that auction. Upon notification of the sales price the Company evaluated and declined the purchase offer.

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. Future payments for the closing, decommissioning and recovery of the remaining investment in Maine Yankee are estimated to be approximately $624.6 million in 2000 dollars including a remaining decommissioning obligation of $278.1 million.

Page 22 of 42

On January 19, 1999, Maine Yankee and the active interveners filed an Offer of Settlement with the FERC which the FERC has approved. As a result, all issues raised in the FERC proceeding, including recovery of anticipated future payments for closing, decommissioning and recovery of the remaining investment in Maine Yankee are resolved. Also resolved are the issues raised by the secondary purchasers, who purchased Maine Yankee power through agreements with the original owners, by limiting the amounts they will pay for decommissioning the Maine Yankee plant and by settling other points of contention affecting individual secondary purchasers. As a result, it is possible that the Company will not be able to recover approximately $.5 million of these costs.

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.

On August 31, 1998, a FERC Administrative Law Judge recommended that the owners of Connecticut Yankee, including the Company, may collect from customers $350.0 million for decommissioning the Connecticut Yankee nuclear power plant rather than the $426.7 million requested. The settlement was approved on July 26, 2000. It provides for a lower cost of service for the period through June 29, 2007 and for full recovery of those costs as they are incurred.

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 system capacity.

Vermont Yankee

During 1996, Vermont Yankee initiated a Design Basis Documentation project expected to be complete by December 31, 2001. This project was undertaken to incorporate all design documentation into a centralized system. The objective is to ensure that Vermont Yankee maintains its safety margins in connection with any plant modifications. The Design Basis Documentation project will create a set of design basis documents which will support more efficient systematic problem solving, maintenance, and system overview. This effort supports the safe, cost effective, long term operation of the Vermont Yankee Plant. Vermont Yankee received FERC approval in 1996 to defer these unrecovered study costs and amortize the costs through billings to Sponsors over the remaining license life of the Plant. The Company's 35% share of the total cost for this Project is expected to be $6.2 million by the 2001 planned project completion.

On October 15, 1999, the Company and the other owners of Vermont Yankee accepted a bid for sale of the plant to AmerGen Energy Co., which is owned by PECO Energy Company and British Energy. On November 17, 1999, Vermont Yankee executed an Asset Purchase Agreement with AmerGen Energy Co. The Agreement is subject to several conditions, including approvals or specific rulings by various regulatory authorities. As such, execution of the Agreement does not provide assurance that the sale will occur. This agreement will also involve the Company entering into a contract to purchase a portion of the power produced by this plant.

Page 23 of 42

Within the original sales terms, Vermont Yankee estimates that the price to be paid by AmerGen for the non-transmission assets will range from $10 million to $23.5 million depending on when the sale occurs. Additionally, Vermont Yankee's current owners will make a one-time payment of approximately $54.0 million to pre-pay the plant's decommissioning fund and to pay the Texas, Maine and Vermont Low-Level Waste compact fees. Based on the expected regulatory treatment of these costs, the Company does not believe the sale will have a material impact on the financial condition or operation of the Company. All scheduled proceedings before the Vermont Public Service Board for approval of the sale have ended and a PSB decision was expected in mid to late October subject to requests by the petitioners to withhold a decision in order to allow ongoing negotiations among the stakeholders parties to conclude. The PSB has issued an order giving AmerGen, Vermont Yankee and its sponsors, and the DPS until November 15, 2000 to file a settlement agreement; if none is filed, the PSB has stated it will issue its decision in this docket shortly thereafter. The Company does not know if these negotiations will prove successful and cannot predict whether any resulting terms will receive and meet petitioner needs for appropriate regulatory approvals.

Maine Yankee, Connecticut Yankee and Yankee Atomic Decommissioning Costs

Presently, 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. As of September 30, 2000, the company has completed its obligation for decommissioning costs (based on current estimates) related to Yankee Atomic. The Company's share of remaining costs with respect to Maine Yankee and Connecticut Yankee's decisions to discontinue operation is estimated to be $10.6 million and $4.8 million, respectively, at September 30, 2000. These amounts are subject to ongoing review and revisions and are reflected in the accompanying 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. 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.

Generating Units

The Company owns and operates 20 hydroelectric generating units and two gas turbines and one diesel peaking unit with a combined nameplate capability of 73.7 mW.

The Company is currently in the process of relicensing or preparing to relicense eight separate hydroelectric projects under the Federal Power Act. These projects, some of which are grouped together under a single license, represent approximately 29.9 mW, or about 66.8% of the Company's total hydroelectric nameplate capacity. In the new licenses, the FERC is expected to impose conditions designed to address the impact of the projects on fish and other environmental concerns. The Company is unable to predict the specific impact of the imposition of such

Page 24 of 42

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.

In addition, the Company maintains joint-ownership interests in Joseph C. McNeil, a 53 mW wood, gas and oil-fired unit and Wyman #4, a 619 mW oil-fired unit.

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

In August 2000, talks broke down, and the VNRC called publicly for removal of the dam. The Company has initiated broader discussions with VNRC, Trout Unlimited, the Vermont Agency of Natural Resources and other parties, related to the economic, reliability and environmental issues that Peterson's removal would create. Management cannot predict the outcome of this issue or the cost of replacement power, if any.

Transmission Matters

Vermont Electric Power Company, Inc. ("VELCO") owns and operates most of the high voltage transmission system in Vermont. The Company owns 56.8% of the Class B common stock of VELCO and 46.6% of the Class C preferred stock of VELCO. Approximately 47% of VELCO's costs are borne by the Company.

On March 22, 2000, the phase angle regulator ("PAR"), which controls power flows over the transmission line between Plattsburg, New York, and Milton, Vermont, suffered a serious failure of insulation in its windings. Automatic equipment immediately took the line out of service. Operations were restored within a week, but without the PAR. The PAR, which is owned by the New York Power Authority ("NYPA"), will be repaired. VELCO has requested NYPA to commence repairs, and has informed NYPA that VELCO will bear the cost of repair, to the extent that regulatory authorities do not allocate any of the costs to others. The final costs to repair the PAR and CV's share of such costs is not currently known. The unit has been shipped to the repair facility and is expected to be returned to service by about February 2001.

To compensate for the loss of PAR control, VELCO plans to operate the affected transmission line during high load periods by employing inductor coils to provide impedance to restrict flows across the line. This mode of operation will increase reactive power support requirements in Vermont. Consequently, VELCO has installed one synchronous condenser near the Vermont terminus of this line to provide that support. The unit will be operable as either a generator or a synchronous condenser. VELCO received all required regulatory approvals and permits required for the installation.

The total cost of the facilities VELCO has installed will be substantial (approximately $10.0 million of expenses through April 2001). Such costs will be spread among all electric customers in New England. The total cost to be borne by VELCO will be about 5% of the total.

Page 25 of 42

VELCO is also in the process of installing a Flexible Alternating Current Transmission System ("FACTS") device which will, by itself, provide the reactive support required for the

operation of this Plattsburg, NY to Milton, VT line. The FACTS device is on schedule to be in service May 1, 2001.

The start-up of the FACTS device will significantly reduce the current need for the Joseph C. McNeil generating plant to run in support of area reliability.

Merrimack Unit #2

Until its termination on April 30, 1998, the Company purchased power and energy from Merrimack Unit #2, pursuant to a contract dated July 16, 1966 entered into by and between VELCO and PSNH. Pursuant to the contract, as amended, VELCO agreed to reimburse PSNH, in the proportion which the VELCO quota bears to the demonstrated net capability of the plant, for all fixed costs of the unit and operating costs of the unit incurred by PSNH, which are reasonable and cost-effective for the remaining term of the VELCO contract. In early 1998, PSNH took the Merrimack Unit #2 facility off line, shut it down and commenced a maintenance outage. In February, March and April of 1998, PSNH billed VELCO for costs to complete the maintenance outage. VELCO disputes the validity of a portion of the charges on grounds that the maintenance performed at the unit was to extend the life of the Merrimack plant beyond the term of the VELCO contract and that the charges in connection with said investments were not reasonable and cost-effective for the remaining term of the VELCO contract. As part of the settlement with NU of the Millstone Unit #3 litigation, NU has agreed to indemnify and hold the Company harmless from all liabilities arising from this litigation.

Cogeneration/Independent Power Producers ("IPPs")

A number of IPPs using hydroelectric, biomass, and refuse-burning generation are currently producing energy that is allocated to the Company for the benefit of its customers by operation of Vermont law. The majority of this 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 kilowatt-hour 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, Green Mountain Power ("GMP"), Citizens Utilities and all of Vermont's 15 municipal utilities, filed a petition with the PSB requesting modification of the contracts between the IPPs and the state appointed purchasing agent. The petition is based on unique provisions of the existing contracts and PSB regulations that provide for modifications and alterations that serve the public interest. The petition outlines seven specific elements that, if implemented, would reduce the purchase power costs of these contracts.

On September 3, 1999, the PSB responded to the Company's petition by opening a formal investigation in Docket No. 6270 regarding these contracts. Shortly thereafter, Citizens Utilities, Hardwick Electric Department and the Burlington Electric Department notified the PSB that they were withdrawing from the petition but they will participate in the case as non-moving parties. In a separate action before the Chittenden County Superior Court brought by several IPP owners, GMP's full participation in this PSB proceeding was enjoined. That injunction is now on appeal to the Vermont Supreme Court. The Company, the other moving utilities and the DPS have

Page 26 of 42

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 retain authority to require GMP to provide specific information or to submit any other specific filing. The IPPs have also filed a related proceeding

in the Washington County Superior Court contending that the PSB rules pertaining to IPPs, which the utilities have relied upon, in part, in their petition before the PSB contains a so-called "scrivener's error." By motion filed in the Superior Court in September, 2000, the IPPs have sought summary judgement in this action.

Simultaneously, the PSB has asked the Superior Court to dismiss the IPP's action. At this time, it cannot be determined when the scrivener's error claim will be resolved. In addition, proceedings are continuing in PSB Docket No. 6270. The PSB has not yet established a schedule for final resolution of this matter.

Production and Transmission

Primarily as a result of higher production fuel costs and reduced activity with the alliance with Virginia Power, production and transmission expenses increased $0.3 million for the third quarter of 2000 compared to the third quarter of 1999.

Production and transmission expenses for the nine months of 2000, compared to last year increased by $2.9 million, primarily related to the above factors and a refund in 1999 related to transmission billings to Hydro-Quebec in the first quarter of 1999.

Other Operation

Other operation expenses decreased $2.1 million and $4.5 million for the three and nine months of 2000, respectively, compared to last year, primarily because of the increased deferral of Hydro-Quebec ice storm arbitration costs in 2000.

Maintenance

Principally due to lower service restoration costs because of fewer storms in 2000, maintenance expenses decreased $1.6 million and $2.4 million for the three and nine months of 2000, respectively, compared to the same periods in 1999.

Income Taxes

Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences. For the third quarter, taxes increased slightly due to permanent differences, and for the nine months of 2000, income taxes decreased as a result of lower pre-tax earnings.

Other Income and Deductions

Other income and deductions increased for the third quarter and nine months ended September 30, 2000, primarily due to a non-recurring gain from the Millstone Unit #3 settlement of $5.4 million related to the NRC's 1996 shutdown of the power plant due to operational and management deficiencies. In addition, higher net earnings of $.6 million for the third quarter,

Page 27 of 42

from non-utility subsidiary companies mostly related to lower losses from SmartEnergy's ownership share in HSS contributed to the favorable variance.

Interest on Long-Term Debt

In July 1999, the Company sold $75.0 million aggregate principal amount of 8 1/8% Second Mortgage Bonds due 2004. Accordingly, interest on long-term debt increased for the three and nine months of 2000.

Other Interest Expense

Other interest expense decreased for the third quarter and nine months ending September 30, 2000 compared to same periods last year due to a decrease in average outstanding short-term debt.

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 $48.2 million and $32.1 million for the nine months ended September 30, 2000 and 1999, respectively.

The Company ended the nine months of 2000 with cash and cash equivalents of $60.9 million, an increase of $25.4 million from the beginning of the year. The increase in cash for the nine months of 2000 was the result of $48.2 million provided by operating activities, offset by $15.2 million used for investing activities and $7.6 million used for financing activities.

Operating Activities - Net income, depreciation, deferred income taxes and investment tax credits provided cash of $21.8 million. Approximately $26.4 million of cash was provided by working capital and other operating activities including the impact of deseasonalized rates, reduction in the HQ SFAS 5 write-off, settlement of the Virginia Alliance accounts receivable, and increased amortizations for nuclear refueling outages.

Investing Activities - Construction and plant expenditures consumed cash of approximately $10.3 million, while $.9 million was used for C&LM programs and $4.2 million was used for non-utility investments.

Financing Activities - Dividends paid on common stock were $7.6 million, while preferred stock dividends were $1.3 million. Long-term debt provided $1.8 million and reduction in capital lease obligations required $.8 million.

The level of short-term borrowing fluctuates based on seasonal corporate needs, the timing of long-term financing and market conditions.

On July 30, 1999, the Company sold $75.0 million aggregate principal amount of 8 1/8% Second Mortgage Bonds due 2004 at a price of 99.915%. The net proceeds of the offering were used to repay $15.0 million of outstanding loans under the Company's revolving credit facility and are expected to be used for other general corporate purposes relative to the Company's utility business. In addition, the Company canceled its $40.0 million revolving credit facility.

Page 28 of 42

The Company has an aggregate of $16.9 million of letters of credit with expiration dates of May 31, 2001.

On February 2, 1999, Standard & Poor's Corporation ("Standard & Poor's") lowered its corporate credit rating on the Company to BBB- (triple-'B'-minus) from BBB (triple-'B'), the senior secured rating to BBB+ (triple-'B'-plus) from A- (single-'A'-minus), and the preferred stock rating to BB+ (double-'B' -plus) from BBB- (triple-'B'-minus). In addition, the ratings were also placed on CreditWatch with negative implications. On February 17, 1999, Standard & Poor's rating on the Company's preferred stock was automatically reduced to BB (double-'B')

from BB+ (double -'B' plus) in response to a policy change in the way Standard & Poor's rates preferred stock.

On March 28, 2000, Standard & Poor's reaffirmed that its ratings on the Company remain on CreditWatch with negative implications, reflecting the potentially adverse impact of pending legal and regulatory decisions that could seriously weaken the Company's credit profile.

In this regard, Standard & Poor's had the following excerpted comments:

"Standard & Poor's remains highly concerned about several important events, which are expected to occur in mid- to late-2000 and could result in significantly lower ratings. These events include the outcome of contract renegotiations with key power suppliers, most notably Hydro-Quebec, the arbitration related to the January 1998 ice storm, and a Vermont Supreme Court appeal, offset in part by the pending sale of the Vermont Yankee nuclear plant. Furthermore, if the PSB disallows the full recovery of power costs associated with the Hydro-Quebec contract, the utility may be required to record substantial write-offs. The outcome of key regulatory decisions will be the principal rationale for any rating or outlook adjustments.

CV's ratings reflect a below-average business profile, coupled with a weak financial profile for the current ratings when adjusted for off-balance-sheet power and transmission obligations. The utility's business profile reflects increasingly restrictive regulation, rising power costs, and nuclear asset exposure. This is tempered only partially by a diverse service area economy with limited industrial concentration, regionally competitive rates, and improving operational efficiency."

Standard & Poor's also said "resolution of the CreditWatch listing will depend on the Hydro-Quebec renegotiations, the arbitration related to the January 1998 ice storm, the Vermont Supreme Court appeal, and other state and federal legal proceedings, which could be resolved in mid- to late-2000. In addition, adequate rate relief and/or successful mitigation of high power costs through contract renegotiations or other methods are essential for maintaining ratings".

On February 17, 1999, Duff & Phelps Credit Rating Co. ("Duff & Phelps"), now Fitch, placed the credit ratings of the Company on Rating Watch-Down due to the high level of regulatory and public policy uncertainty in Vermont and the unfavorable ruling by the United States Court of Appeals relating to Connecticut Valley, the Company's wholly owned New Hampshire subsidiary.

On July 16, 1999, Duff & Phelps assigned a rating of "BBB-" (Triple-B-minus) to the Company's then proposed $75 million issue of second mortgage bonds and lowered its rating on the Company's preferred stock to "BB+" (Double-B-plus) from "BBB-" (Triple-B-minus) with all ratings remaining on Rating Watch-Down.

Page 29 of 42

On April 4, 2000, Duff & Phelps reaffirmed the Company's credit ratings and has maintained the ratings on Rating Watch-Down. Duff & Phelps had the following excerpted comments:

"The watch status reflects the continued high level of regulatory and public policy uncertainty in Vermont and the ultimate legal and regulatory outcome associated with the Company's wholly owned subsidiary, Connecticut Valley, which adds risk to the Company's financial profile going forward. Approximately $190 million of debt and preferred securities are affected."

Duff & Phelps also said, "The Company's ratings and watch status incorporate past negative rulings issued by the PSB regarding purchased power costs, which have led to financial instability and uncertainty among electric utilities in Vermont. Consequently, this uncertain public policy environment has directly impacted CV's overall credit quality, resulting in lower coverage ratios and reduced financial flexibility. Positively, CV has taken initiatives to offset the

short-term financial and liquidity constraints of this regulatory induced situation. CV's recent second mortgage issuance (July 1999) provides the Company increased financial flexibility to meet its upcoming mandatory debt and preferred retirements over the next few years while a resolution to Vermont's above-market purchased power obligations, stranded cost recovery and ultimately industry restructuring is attained."

Current credit ratings of the Company's securities by Standard & Poor's and Duff & Phelps remain as follows:

Standard
& Poor's (1)

Duff &
Phelps (2) (3)

Corporate Credit Rating

BBB-

N/A

First Mortgage Bonds

BBB+

BBB

Second Mortgage Bonds

BBB-

  BBB-

Preferred Stock

  BB

    BB+

(1)  All Standard & Poor's ratings are placed on "CreditWatch with negative implications."

(2)  All Duff & Phelps ratings are placed on "Rating Watch--Down."

(3)  In June, 2000, Fitch Ratings Service acquired Duff & Phelps. New rating information will be provided in the future by Fitch.

In 1998, Catamount, replaced its $8.0 million credit facility with a $25.0 million revolving credit/term loan facility maturing November 2006 which provides for up to $25.0 million in revolving credit loans and letters of credit of which $7.3 million was outstanding at September 30, 2000. This facility has a security interest in Catamount's assets. Catamount currently has a $1.2 million letter of credit outstanding to support certain of its obligations in connection with a debt service requirement in the Appomattox Cogeneration project. In addition, letters of credit for $11.0 million are outstanding in support of construction and equity commitments for its Gauley River Power project. Catamount has provided a $2.1 million letter of credit as well as a security interest in the stock of Catamount Energy Corporation securing the payment of cost overruns at the project which is currently behind schedule.

SmartEnergy Water Heating Services, Inc., a wholly owned subsidiary of SmartEnergy, has a secured $1.5 million, seven-year term loan with Bank of New Hampshire with an outstanding balance of $1.3 million at September 30, 2000. The interest rate is fixed at 9.50%.

Page 30 of 42

Financial obligations of the Company's subsidiaries are non-recourse to the Company.

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

financing that the Company may need will be dependent upon its cash needs, the availability of refinancing sources and the prevailing conditions in the financial markets. The Company cannot guarantee that financing sources will be available to the Company at any given time or that the terms of such sources will be favorable.

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.

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, 1999 the Company's VJO projected cost obligation is approximately 47% or $1.0 billion 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 $2.1 billion.

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

In September 1999, an initial two weeks of hearings were held dealing primarily with issues of contract interpretation. The second phase of the arbitration hearings have concluded and a final decision in the case is expected late this year or in early 2001. In accordance with a PSB Accounting Order, the Company has deferred incremental costs associated with this arbitration of approximately $6.3 million through September 30, 2000. The deferred costs have been offset by the incremental revenue from deseasonalized rates that were implemented July 1, 2000, as directed by the Vermont Public Service Board. As of September 30, 2000 excess revenues of $7.4 million have been applied to these deferred costs. While the current regulatory asset

Page 31 of 42

balance is negative ($1.1 million) at September 30, 2000, it is expected to become a positive number because of the ongoing cost of the Hydro-Quebec arbitration, and the expected negative impact of deseasonalized revenues during the fourth quarter.

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 Catamount Resources Corporation, invests in energy generation projects in North America and

Western Europe. Through its wholly owned subsidiaries, Catamount has interests in seven operating independent power projects located in Glenns Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont; Thetford, England; Hopewell, Virginia; and Fort Dunlop, England. In addition, Catamount has interests in a project under construction in Summersville, West Virginia. In November 1999 Catamount created a new subsidiary, Catamount Investment Company LLC, which will provide additional capital for investment in new generation projects. Catamount has partnered with CIT Group, a major equipment finance company, and Dana Commercial Credit Corporation, the finance subsidiary of Dana Corporation. Capital commitments from these two joint venture partners are $60.0 million, expected to be invested over the next four years. Catamount's after-tax earnings were $.5 million and $.3 million for the third quarter of 2000 and 1999, respectively and $.8 million and $1.2 million for the nine months of 2000 and 1999, respectively. In September 2000, Catamount created a new subsidiary, Catamount Energy (Gibralter) Limited. This is a foreign holding company which has been formed for the purpose of providing capital for investments in foreign generation projects.

Catamount has provided a $2.1 million letter of credit as well as a security interest in the stock of Catamount Energy Corporation securing the payment of cost overruns at the Gauley River Power project which is currently behind schedule.

Doug Barba, Executive Vice President and General Manager of Catamount has tendered his resignation and the Company has retained an executive search firm to find a successor for him.

SmartEnergy, also a subsidiary of Catamount Resources Corporation invests in unregulated energy and service related businesses. SmartEnergy also has an ownership interest in HSS. Overall, SmartEnergy incurred after-tax losses of $.1 million and net losses of $.4 million for the third quarter of 2000 and 1999, respectively and net losses of $2.4 million and $1.0 million for the nine months of 2000 and 1999, respectively. HSS establishes a network of affiliate contractors who perform home maintenance repair and improvements via membership. SmartEnergy's investment in HSS is accounted for using the equity method. HSS began operations in the first quarter of 1999 and is subject to risks and challenges similar to a company in the early stage of development. HSS' pre-tax loss for the first nine months of 2000 was $20.0 million, resulting primarily from the national rollout of HSS, of which SmartEnergy's share was $3.7 million incurred in the first quarter of 2000 .

HSS began a test rollout through Sam's Club in late spring 1999. After a successful test market, the national rollout anticipated for year 2000 was accelerated to begin at the end of 1999. In December 1999, HSS announced that it had developed another marketing relationship with TruServ Corporation, the cooperative entity for True Value Hardware Stores. On March 14, 2000, HSS issued 3,500,000 shares of convertible preferred stock. The proceeds, of approximately $32.0 million, net of transaction costs, will be used by HSS to finance the national

Page 32 of 42

rollout of HSS. On October 4, 2000 HSS acquired ServiceBeyond.com, a web-based home

services management company serving the San Diego, Denver and Dallas markets. As a result of the losses that have already been incurred on the Company's investment in HSS, the Company expects to recognize insignificant losses during the balance of calendar year 2000. The Company's current ownership of HSS is 31.3%.

Proposed Formation of Holding Company

In order to further prepare Central Vermont Public Service Corporation for deregulation, on July 24, 1998, the Company filed a petition with the PSB for permission to create a holding company that would have as subsidiaries the Company and non-utility subsidiaries, Catamount and SmartEnergy. The Company believes that a holding company structure will facilitate the Company's transition to a deregulated electricity market. The proposed holding company

formation must also be approved by Federal regulators, including the Securities and Exchange Commission and the FERC, and by the Company's shareholders. The Company has negotiated an agreement regarding the formation of a holding company with the DPS. The agreement establishes a code of conduct and affiliate transaction rules. The Company has informed the PSB that it is prepared to present the Code of Conduct and affiliate transaction rules to the PSB for it's review and approval, while the DPS has informed the PSB that it prefers to defer the PSB's review until other regulatory issues are resolved.

Company has also agreed to not further pursue the holding company proceeding before the PSB until additional progress is made on other restructuring initiatives.

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.

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; (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 Vermont service territory.

The Working Group

On July 22, 1998, the Governor of Vermont issued an Executive Order establishing the Working Group on Vermont's Electricity Future to lead a new effort to review the issues of potential restructuring of Vermont's electric industry. The Working Group was created to determine how restructuring the electric industry in Vermont could reduce both current and long-term electric costs for all classes of Vermont electric consumers. The Working Group was asked

Page 33 of 42

to provide a fact-based analysis of the options for electric industry restructuring and the impact of such industry changes on consumers and upon Vermont utilities. Further, the Working Group

was directed by the Governor to gather information on and evaluate the possible consequences of the current financial status of Vermont electric utilities.

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

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

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

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

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

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

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

Public Service Board Docket No. 6140

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

On March 3, 1999, the Company filed its Restructuring Plan, a Working Plan to restructure a significant portion of Vermont's Electric Utility Industry, with the PSB and parties in Docket No. 6140. The Company's plan was a joint plan with Green Mountain Power Corporation ("GMP").

Page 34 of 42

On July 12, 1999, the PSB issued a Status Order concluding that the objective of implementing power supply reform may be advanced more effectively in ways other than holding further

technical conferences in this docket. Absent good reason to hold one or more technical conferences pertinent to power supply reform, the PSB indicated that the docket would be closed on December 31, 1999, which action has occurred. As a companion proceeding to its Docket No. 6140 investigation, on January 19, 1999, the PSB issued an order opening a new contested case proceeding, Docket No. 6140-A, where it indicated that it intended to issue final, binding and appealable orders concerning matters related to the reform and restructuring of Vermont's electric utility industry. Initially, the PSB notified parties that it intended proceedings in Docket No. 6140-A to consider matters associated with the bankruptcy of one or more of the Vermont electric utilities. After an opportunity for comment, the focus of the proceeding was amended to

consider the principles, authority and proposals for reform of Vermont's electric power supply. This included issues associated with the scope and extent of the Board's authority to approve "securitization" and other financing proposed to be entered into in connection with the buy-out or buy-down of power contracts and the criteria to be applied by the PSB when considering voluntary utility restructuring proposals.

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

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

In contrast, Vermont Electric Power Producers, Inc.("VEPP"), purchasing agent for the purchase of power from qualifying facilities pursuant to PSB Rule 4.100, proposed to use administrative securitization to finance the reform of its power purchase contracts. However, at the request of all commenting parties, the PSB determined to withhold judgment on the issue as to whether the PSB had jurisdiction to authorize a VEPP financing until such time as a specific proposal was actually filed with the PSB. In the absence of any requests for further investigation or action to be filed within 30 days of the Docket No. 6140-A Order, the PSB indicated that this investigation would be closed, which action has occurred. To follow up on its proposal, on June 15, 2000, VEPP filed a petition requesting that the PSB issue a declaratory ruling confirming the authority of the PSB to issue voluntary administrative securitization orders relative to those qualifying facilities currently holding purchase power contract under PSB Rule 4.100. By order dated June 30, 2000 the PSB opened Docket No. 6396. As part of the Docket proceedings, the PSB convened a workshop to hear detailed presentations on the VEPP proposal. Parties are to

Page 35 of 42

make filings of their positions and arguments on Docket issues by mid-November, 2000. A final order in that proceeding is expected by year end.

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

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

The Company is aggressively pursuing implementation of the Restructuring Plan which includes the following elements:

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

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

Contract and asset disposition: seeking to sell power purchase contracts and generating assets, including the Company's interest in the Vermont Yankee nuclear generating plant. On October 15, 1999, the Company and the other owners of Vermont Yankee accepted a bid for sale of the plant to AmerGen Energy Company ("AmerGen"), which is owned by PECO Energy Company and British Energy. This transaction will also involve taking back a contract to purchase a portion of the power produced by this plant. The Vermont Yankee sale still needs to be approved by the Vermont PSB. On November 4, 1999 the PSB opened Docket No. 6300 to consider the issues attendant to the approval of the sale of Vermont Yankee and approval of various related agreements including the Company's agreement to continue to purchase its share of the output of Vermont Yankee. A final order in that proceeding is expected by year end.

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

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

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

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

Page 36 of 42

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

The Company believes that implementation of its Restructuring Plan is a critical element to improving its future financial performance and to providing its customers with more stable electric rates and the continuation of efficient and reliable electric service. The key contingency of the Company's Restructuring Plan is regulatory approval of a rate schedule that will allow the Company to recover the costs of the restructuring. If the financial restructuring described in this section is completed in conjunction with the deregulation of Vermont's electric industry described in "Electric Industry Restructuring," the Company anticipates that its utility financial performance and prospects will improve significantly.

Public Service Board Docket No. 6330

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

permit the Companies to suspend their provision of power supply Services ("Generation Service") to customers located within their respective service territories;
permit the Companies to amend their service tariff obligations to clarify that they retain their exclusive service franchises as providers of electric delivery services ("Delivery Service") to customers within their respective service territories;
permit the Companies to implement a Retail Open Access Tariff ("R-OAT") that enables customers located within the Companies' respective service territories to choose their power supplier from an array of approved energy service providers ("ESP"), and to purchase Generation Service from such ESPs at market-determined prices;
select through a competitive bidding process an ESP or ESPs to deliver "Default Service" for energy to customers located within the Companies' service territories that do not otherwise have an arrangement with an ESP for the Provision of Generation Service;
select through a competitive bidding process an ESP or ESPs to deliver "Transition Service" for energy to customers located within the Companies' service territories; and

Page 37 of 42

approve revisions and modifications to the Companies' tariffs to implement voluntary retail access within the Companies' respective service territories as provided for pursuant to this Petition.

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

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

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

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

Competition and Risk Factors

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

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

Page 38 of 42

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 $45.8 million on a pre-tax basis as of September 30, 2000. 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.

The Securities and Exchange Commission has questioned the ability of certain utility companies continuing the application of SFAS No. 71 where legislation provides for the transition to retail competition. Deregulation of the price of electricity issues related to the application of SFAS No. 71 and 101, as to when and how to discontinue the application of SFAS No. 71 by utilities during transition to competition has been referred to the Financial Accounting Standards Board's Emerging Issues Task Force ("EITF").

The EITF has reached a tentative consensus, and no further discussion is planned, that regulatory assets should be assigned to separable portions of the Company's business based on the source of the cash flows that will recover those regulatory assets. Therefore, if the source of the cash flows is from a separable portion of the Company's business that meets the criteria to apply SFAS No. 71, those regulatory assets should not be written off under SFAS No. 101, "Accounting for the Discontinuation of Application of SFAS No. 71," but should be assessed under paragraph 9 of SFAS No. 71 for reliability.

SFAS No. 121, "Accounting for the Impairment of Long Lived Assets and for Long-Lived Assets to Be Disposed Of," which was 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 December 31, 1999, based upon the regulatory environment within which the Company currently operates, SFAS No. 121 did not have an impact on the Company's financial position or results of operations. Competitive influences or regulatory developments may impact this status in the future.

Because the Company is unable to predict what form possible future restructuring legislation will take, it cannot predict if or to what extent SFAS Nos. 71 and 121 will continue to be applicable in the future. In addition, if the Company is unable to mitigate or otherwise recover stranded costs that could arise from any potentially adverse legislation or regulation, the Company would have to assess the likelihood and magnitude of losses incurred under its power contract obligations.

As such, the Company cannot predict whether any restructuring legislation enacted in Vermont or New Hampshire, once implemented, would have a material adverse effect on the Company's operations, financial condition or credit ratings. However, the Company's failure to recover a significant portion of its purchased power costs, would likely have a material adverse effect on the Company's results of operations, cash flows, ability to obtain capital at competitive rates and ability to exist as a going concern. It is possible that stranded cost exposure before mitigation could exceed the Company's current total common stock equity.

Page 39 of 42

Recent Accounting Pronouncements

In June 1998, the FASB issued SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. In June 1999, the FASB issued Statement No. 137, Accounting for Derivative Instruments and Hedging Activities -- Deferral of the Effective Date of SFAS No. 133 and in June 2000, issued SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Activities, an amendment to FASB Statement No. 133. These Statements establish

accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. These Statements require 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.

SFAS No. 133, as amended, is effective for fiscal years beginning after June 15, 2000. A company may also implement this Statement as of the beginning of any fiscal quarter after issuance (that is, fiscal quarters beginning June 16, 1998 and thereafter). SFAS No. 133 cannot be applied retroactively. SFAS No. 133 must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts. With respect to hybrid instruments, a company may elect to apply SFAS 133, as amended, to (1) all hybrid contracts, (2) only those hybrid instruments that were issued, acquired, or substantively modified after December 31, 1997, or (3) only those hybrid instruments that were issued, acquired, or substantively modified after December 31, 1998. The Company has organized an implementation team and established a schedule for implementation by January 1, 2001, as required by SFAS 133, as amended. As of September 30, 2000, the company has taken an inventory of the majority of its contracts and for each one of those contracts has considered the impact of SFAS 133 on such contracts. Based on such evaluation and work performed to-date, SFAS 133, as amended, is not expected to have a material effect on the financial position or results of operations of the Company.

Forward Looking Statements

This document contains statements that are forward looking. These statements are based on current expectations that are subject to significant risks and uncertainties. Actual results will depend, among other things, upon the actions of regulators, the Company's pending rate cases before the PSB, the outcome of litigation involving Connecticut Valley and Central Vermont, the performance of Vermont Yankee, weather conditions, and the performance of the Company's unregulated businesses. The Company cannot predict the outcome of any of these matters.

Page 40 of 42

CENTRAL VERMONT PUBLIC SERVICE CORPORATION

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

On August 7, 1997, the Company and eight other non-operating owners of Millstone Unit #3 ("Unit #3") filed a demand for arbitration with Connecticut Light and Power Company and Western Massachusetts Electric Company, both NU affiliates, and lawsuits against NU and its trustees. The arbitration and lawsuits sought to recover costs associated with replacement power, operation and maintenance costs and other costs resulting from the shutdown of Unit #3. The non-operating owners claim that NU and two of its wholly owned subsidiaries failed to comply with NRC's regulations, failed to operate the facility in accordance with good operating practice and attempted to conceal their activities from the non-operating owners and the NRC.

On July 27, 2000, the Company executed a settlement agreement with NU, resolving all issues asserted by the Company in the arbitration and lawsuits. The settlement became effective on August 4, 2000, following approval of the Company's withdrawal from the arbitration and litigation. The settlement agreement provided for a cash settlement of $5,445,000 which has been paid to the Company by NU, the right of the Company to participate in the auction of the Millstone plants, and indemnification by NU of the Company's liability, if any, arising out of the litigation between VELCO and NU's subsidiary, Public Service of New Hampshire ("PSNH"), relating to costs of the Merrimack #2 plant. Under the settlement agreement, the Company released NU from all claims arising from the outage and agreed to waive certain rights against NU which the Company believes could have hindered the auction.

Except as otherwise described under Management's Discussion and Analysis of Financial Condition and Results of Operations, Item 2, there are no other material pending legal proceedings, other than ordinary routine litigation incidental to the business, to which the company or any of its subsidiaries is a party or to which any of their property is subject.

Items 2 and 3 and 4. None.

Item 5. None.

Item 6. Exhibits and Reports on Form 8-K.

a. List of Exhibits

27. Financial Data Schedule

b. Item 5. Other events, dated July 27, 2000 re. Settlement Agreement with Northeast
Utilities resolving issues related to the Millstone Nuclear Power Station.

Page 41 of 42

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 November 13, 2000

Page 42 of 42

	Standard & Poor's (1)	Duff & Phelps (2) (3)
Corporate Credit Rating	BBB-	N/A
First Mortgage Bonds	BBB+	BBB
Second Mortgage Bonds	BBB-	BBB-
Preferred Stock	BB	BB+

(1) All Standard & Poor's ratings are placed on "CreditWatch with negative implications."
(2) All Duff & Phelps ratings are placed on "Rating Watch--Down."
(3) In June, 2000, Fitch Ratings Service acquired Duff & Phelps. New rating information will be provided in the future by Fitch.