UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.   20549

FORM 10-Q

(Mark One)
x	QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended   June 30, 2008
or
¨	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)

Vermont (State or other jurisdiction of incorporation or organization)	03-0111290 (IRS Employer Identification No.)
77 Grove Street, Rutland, Vermont (Address of principal executive offices)	05701 (Zip Code)
Registrant's telephone number, including area code 802-773-2711
(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 by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨(Do not check if a smaller reporting company)	Smaller reporting company	¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.  As of July 31, 2008 there were outstanding 10,346,923 shares of Common Stock, $6 Par Value.

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Form 10-Q for Period Ended June 30, 2008
Table of Contents
PART I.   Financial Information:
	Item 1.	Financial Statements
			Condensed Consolidated Statements of Income	2
			Condensed Consolidated Statements of Comprehensive Income	3
			Condensed Consolidated Balance Sheets	4
			Condensed Consolidated Statements of Cash Flows	6
			Condensed Consolidated Statement of Changes in Common Stock Equity	7
			Notes to Condensed Consolidated Financial Statements	8
	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		21
	Item 3.	Quantitative and Qualitative Disclosures about Market Risk		30
	Item 4.	Controls and Procedures		30
PART II.   Other Information:
	Item 1.	Legal Proceedings		31
	Item 1A.	Risk Factors		31
	Item 4.	Submission of Matters to a Vote of Security Holders		31
	Item 5.	Other Information		32
	Item 6.	Exhibits		32
SIGNATURE				33

Page 1 of 33

PART I. FINANCIAL INFORMATION

Item 1.  Financial Information

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(dollars in thousands, except per share data)
(unaudited)
	Three months ended June 30						Six months ended June 30
	2008			2007			2008			2007
Operating Revenues	$	84,487		$	77,380		$	175,711		$	164,076
Operating Expenses
Purchased Power - affiliates		16,270			11,817			32,738			27,955
Purchased Power - other		25,012			28,002			51,450			54,124
Production		2,836			2,806			6,178			5,945
Transmission - affiliates		4,054			1,416			7,443			2,913
Transmission - other		3,847			3,805			8,321			7,992
Other operation		13,294			13,219			28,039			27,007
Maintenance		6,473			8,471			12,642			13,928
Depreciation		3,899			3,775			7,768			7,514
Taxes other than income		3,713			3,776			7,752			7,504
Income tax expense (benefit)		846			(594	)		2,705			2,244
Total Operating Expenses		80,244			76,493			165,036			157,126
Utility Operating Income		4,243			887			10,675			6,950
Other Income
Equity in earnings of affiliates		4,014			1,589			8,199			3,291
Allowance for equity funds during construction		47			(1	)		64			16
Other income		869			1,049			1,636			2,116
Other deductions		(857	)		(427	)		(2,165	)		(1,020	)
Income tax expense		(1,458	)		(364	)		(2,883	)		(890	)
Total Other Income		2,615			1,846			4,851			3,513
Interest Expense
Interest on long-term debt		2,176			1,799			4,113			3,598
Other interest		704			414			1,535			644
Allowance for borrowed funds during construction		(23	)		(1	)		(31	)		(6	)
Total Interest Expense		2,857			2,212			5,617			4,236
Net Income		4,001			521			9,909			6,227
Dividends declared on preferred stock		92			92			184			184
Earnings available for common stock	$	3,909		$	429		$	9,725		$	6,043
Per Common Share Data:
Basic earnings per share	$	0.38		$	0.04		$	0.94		$	0.59
Diluted earnings per share	$	0.38		$	0.04		$	0.94		$	0.58
Average shares of common stock outstanding - basic		10,337,893			10,186,907			10,306,699			10,161,336
Average shares of common stock outstanding - diluted		10,397,675			10,307,095			10,387,289			10,355,990
Dividends declared per share of common stock	$	0.23		$	0.23		$	0.69		$	0.69

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

Page 2 of 33

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(dollars in thousands)
(unaudited)
	Three months ended June 30				Six months ended June 30
	2008		2007		2008		2007
Net Income	$	4,001	$	521	$	9,909	$	6,227
Other comprehensive income, net of tax:
Defined benefit pension and postretirement medical plans:
Portion reclassified through amortizations, included in benefit
costs and recognized in net income:
Actuarial losses, net of income taxes of $1, $3, $1 and $6		-		4		1		9
Prior service cost, net of income taxes of $2, $3, $5 and $5		4		4		6		7
		4		8		7		16
Portion reclassified due to adoption of SFAS 158 measurement
provision, included in retained earnings:
Prior service cost, net of income taxes of $0, $0, $2 and $0		-		-		4		-
		-		-		4		-
Comprehensive income adjustments		4		8		11		16
Total comprehensive income	$	4,005	$	529	$	9,920	$	6,243

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

Page 3 of 33

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(dollars in thousands, except share data)
(unaudited)
	June 30, 2008		December 31, 2007
ASSETS
Utility plant
Utility plant, at original cost	$	544,578	$	538,229
Less accumulated depreciation		240,157		235,465
Utility plant, at original cost, net of accumulated depreciation		304,421		302,764
Property under capital leases, net		6,333		6,788
Construction work-in-progress		15,259		9,611
Nuclear fuel, net		1,603		1,105
Total utility plant, net		327,616		320,268
Investments and other assets
Investments in affiliates		96,902		93,452
Non-utility property, less accumulated depreciation     ($3,690 in 2008 and $3,681 in 2007)		1,663		1,646
Millstone decommissioning trust fund		5,513		5,645
Other		6,556		7,504
Total investments and other assets		110,634		108,247
Current assets
Cash and cash equivalents		6,562		3,803
Restricted cash		1		62
Special deposits		741		1,000
Accounts receivable, less allowance for uncollectible accounts     ($2,095 in 2008 and $1,751 in 2007)		22,923		24,086
Accounts receivable - affiliates, less allowance for uncollectible accounts     ($48 in 2008 and 2007)		123		254
Unbilled revenues		15,548		17,665
Materials and supplies, at average cost		5,253		5,461
Prepayments		4,181		8,942
Deferred income taxes		5,738		3,638
Power-related derivatives		3,290		707
Other current assets		447		1,081
Total current assets		64,807		66,699
Deferred charges and other assets
Regulatory assets		30,648		31,988
Other deferred charges - regulatory		18,698		8,988
Other deferred charges and other assets		4,742		4,124
Total deferred charges and other assets		54,088		45,100
TOTAL ASSETS	$	557,145	$	540,314

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

Page 4 of 33

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(dollars in thousands, except share data)
(unaudited)
	June 30, 2008			December 31, 2007
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock, $6 par value, 19,000,000 shares authorized,      12,549,552 issued and 10,345,785 outstanding at June 30, 2008 and      12,474,687 issued and 10,244,559 outstanding at December 31, 2007	$	75,297		$	74,848
Other paid-in capital		57,228			56,324
Accumulated other comprehensive loss		(367	)		(378	)
Treasury stock, at cost, 2,203,767 shares at June 30, 2008 and      2,230,128 shares at December 31, 2007		(50,135	)		(50,734	)
Retained earnings		111,303			108,747
Total common stock equity		193,326			188,807
Preferred and preference stock not subject to mandatory redemption		8,054			8,054
Preferred stock subject to mandatory redemption		1,000			2,000
Long-term debt		172,950			112,950
Capital lease obligations		5,432			5,889
Total capitalization		380,762			317,700
Current liabilities
Current portion of preferred stock subject to mandatory redemption		1,000			1,000
Current portion of long-term debt		3,000			3,000
Accounts payable		3,688			6,253
Accounts payable - affiliates		11,792			13,205
Notes payable		10,800			63,800
Dividends payable		2,379			-
Nuclear decommissioning costs		1,992			2,309
Power-related derivatives		8,340			3,225
Other current liabilities		22,146			20,761
Total current liabilities		65,137			113,553
Deferred credits and other liabilities
Deferred income taxes		35,895			33,666
Deferred investment tax credits		3,151			3,341
Nuclear decommissioning costs		8,781			9,580
Asset retirement obligations		3,298			3,200
Accrued pension and benefit obligations		15,707			19,874
Power-related derivatives		8,855			4,592
Other deferred credits - regulatory		11,337			9,395
Other deferred credits and other liabilities		24,222			25,413
Total deferred credits and other liabilities		111,246			109,061
Commitments and contingencies
TOTAL CAPITALIZATION AND LIABILITIES	$	557,145		$	540,314

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

Page 5 of 33

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
(unaudited)
	Six months ended June 30
	2008			2007
Cash flows provided (used) by:
OPERATING ACTIVITIES
Net income	$	9,909		$	6,227
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of affiliates		(8,199	)		(3,291	)
Distributions received from affiliates		4,868			2,510
Depreciation		7,768			7,514
Deferred income taxes and investment tax credits		(291	)		(55	)
Non-cash employee benefit plan costs		2,926			3,604
Regulatory and other amortization, net		(752	)		(2,247	)
Other non-cash expense, net		2,595			1,644
Changes in assets and liabilities:
Decrease in accounts receivable and unbilled revenues		2,075			5,764
Decrease in accounts payable		(3,195	)		(3,411	)
Increase in accrued income taxes		3,215			-
Decrease in other current assets		2,638			1,265
Increase in special deposits and restricted cash for power collateral		(679	)		(1,654	)
Employee benefit plan funding		(7,226	)		(7,879	)
Increase (decrease) in other current liabilities		476			(1,327	)
Other non-current assets and liabilities and other		(231	)		(16	)
Net cash provided by operating activities		15,897			8,648
INVESTING ACTIVITIES
Construction and plant expenditures		(15,721	)		(9,772	)
Investments in available-for-sale securities		(617	)		(816	)
Proceeds from sale of available-for-sale securities		478			734
Proceeds from sale of property		-			342
Return of capital from investments in affiliates		96			108
Other investments and capital expenditures		(113	)		(270	)
Net cash used for investing activities		(15,877	)		(9,674	)
FINANCING ACTIVITIES
Proceeds from issuance of common stock		1,508			974
Common and preferred dividends paid		(4,921	)		(4,857	)
Proceeds from issuance of first mortgage bonds		60,000			-
Repayment of Notes Payable		(53,000	)		-
Debt issuance costs		(691	)		-
Proceeds from borrowings under revolving credit facility		9,300			19,600
Repayments under revolving credit facility		(9,300	)		(13,150	)
Retirement of preferred stock subject to mandatory redemption		(1,000	)		(1,000	)
Decrease in special deposits held for preferred stock redemptions		1,000			1,000
Other		(157	)		(149	)
Net cash provided by financing activities		2,739			2,418
Net increase in cash and cash equivalents		2,759			1,392
Cash and cash equivalents at beginning of the period		3,803			2,799
Cash and cash equivalents at end of the period	$	6,562		$	4,191

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

Page 6 of 33

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN COMMON STOCK EQUITY
(in thousands, except share data)
(unaudited)
	Common Stock						Accumulated			Treasury Stock
					Other		Other
	Shares				Paid-in		Comprehensive									Retained
	Issued		Amount		Capital		Loss			Shares			Amount			Earnings			Total
Balance, December 31, 2007		12,474,687	$	74,848	$	56,324	$	(378	)		2,230,128		$	(50,734	)	$	108,747		$	188,807
Adjust to initially apply SFAS 158 measurement provision, net of tax								4									(50	)		(46	)
Net income																	9,909			9,909
Other comprehensive income								7												7
Dividend reinvestment plan											(26,361	)		599						599
Stock options exercised		58,000		348		772														1,120
Share-based compensation		16,865		101		92														193
Dividends declared on common and preferred stock																	(7,300	)		(7,300	)
Amortization of preferred stock issuance expense						8														8
Gain on issuance of treasury stock						29														29
Loss on reacquisition of capital stock						3											(3	)		0
Balance, June 30, 2008		12,549,552	$	75,297	$	57,228	$	(367	)		2,203,767		$	(50,135	)	$	111,303		$	193,326

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

Page 7 of 33

CENTRAL VERMONT PUBLIC SERVICE CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - BUSINESS ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General Description of Business Central Vermont Public Service Corporation ("we", "us", "CVPS" or the "company") is the largest electric utility in Vermont.  We engage principally in the purchase, production, transmission, distribution and sale of electricity.  We serve approximately 159,000 customers in nearly two-thirds of the towns, villages and cities in Vermont.  Our Vermont utility operation is our core business.  We typically generate most of our revenues through retail electricity sales.  We also sell excess power, if any, to third parties in New England and to ISO-New England, the operator of the region's bulk power system and wholesale electricity markets.  The resale revenue generated from these sales helps to mitigate our power supply costs.

Our wholly owned subsidiaries include Custom Investment Corporation, C.V. Realty, Inc., Central Vermont Public Service Corporation - East Barnet Hydroelectric, Inc. and Catamount Resources Corporation.  We have equity ownership interests in Vermont Yankee Nuclear Power Corporation ("VYNPC"), Vermont Electric Power Company, Inc. ("VELCO"), Vermont Transco LLC ("Transco"), Maine Yankee Atomic Power Company ("Maine Yankee"), Connecticut Yankee Atomic Power Company ("Connecticut Yankee") and Yankee Atomic Electric Company ("Yankee Atomic").

Basis of Presentation These unaudited interim financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission.  Accordingly, certain information and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") have been condensed or omitted.  In our opinion, the accompanying interim financial statements reflect all normal, recurring adjustments considered necessary for a fair presentation.  Operating results for the interim periods presented herein may not be indicative of the results that may be expected for the year.  The financial statements incorporated herein should be read in conjunction with the consolidated financial statements and accompanying notes included in our annual report on Form 10-K for the year ended December 31, 2007.

Regulatory Accounting Our utility operations are regulated by the Vermont Public Service Board ("PSB"), the Connecticut Department of Public Utility and Control and the Federal Energy Regulatory Commission ("FERC") with respect to rates charged for service, accounting, financing and other matters pertaining to regulated operations.  As such, we prepare our financial statements in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation ("SFAS 71").  The application of SFAS 71 results in differences in the timing of recognition of certain expenses from those of other businesses and industries.  In the event we determine that our utility operations no longer meet the criteria for applying SFAS 71, the accounting impact would be an extraordinary non-cash charge to operations of an amount that would be material unless stranded cost recovery is allowed through a rate mechanism.  Based on a current evaluation of the factors and conditions expected to impact future cost recovery, we believe future recovery of our regulatory assets is probable.  See Note 4 - Retail Rates and Regulatory Accounting.

Derivative Financial Instruments Our derivative financial instruments include certain power contracts and financial transmission rights.  We enter into forward sale contracts to reduce price volatility, since our long-term power forecasts show energy purchases and production in excess of load requirements.  We enter into forward purchase contracts for replacement energy during Vermont Yankee scheduled refueling outages.  We are able to economically hedge our exposure to congestion charges that result from constraints on the transmission system with Financial Transmission Rights ("FTRs").  FTRs are awarded to the successful bidders in periodic auctions, in which we participate, that are administered by ISO-New England.

Based on a PSB-approved Accounting Order, we record the changes in fair value of power-related derivative financial instruments as deferred charges or deferred credits on the balance sheet, depending on whether the fair value is an unrealized loss or gain.  The corresponding offsets are recorded as current and long-term assets or liabilities depending on the duration of the contracts.  In the second quarter of 2008, we entered into several forward sale contracts for the sale of approximately 29 percent of our forecasted excess power available for resale in 2009.  At June 30, 2008 the estimated fair value of these derivatives was an unrealized loss of $1.3 million.  See Note 5 - Fair Value for a discussion of the estimated fair value of all of our power-related derivatives.

Reclassifications Certain prior year amounts have been reclassified to conform to the current year presentation. Power-related derivatives of $0.7 million have been reclassified from Other current assets to a separate line on the December 31, 2007 Condensed Consolidated Balance Sheet.  We reclassified prior year amounts included on the Condensed Consolidated Statements of Cash Flow for the six months ended June 30, 2007.  Reduction in capital lease obligations of $(0.4) million and Stock reacquisition and other of $0.2 million are now included in Other within Financing activities.

Page 8 of 33

Recently Adopted Accounting Policies

Fair Value: On January 1, 2008, we adopted FASB Statement No. 157, Fair Value Measurements ("SFAS 157"), which addresses how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under U.S. GAAP.  This standard applies prospectively to new fair value measures of financial instruments and recurring fair value measurements of non-financial assets and non-financial liabilities.  SFAS 157 does not expand the use of fair value, but it has applicability to several current accounting standards that require or permit us to measure assets and liabilities at fair value.

On February 12, 2008, the FASB issued FASB Staff Position No. FAS 157-2, Effective Date of FASB Statement No. 157, which amends SFAS 157 by allowing entities to delay its effective date by one year for non-financial assets and non-financial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis.  We have deferred the application of SFAS 157, related to asset retirement obligations until January 1, 2009, as permitted by this FSP.

SFAS 157 defines fair value as "the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date," or the "exit price."  We must determine that fair value of an asset or liability based on the assumptions that market participants would use in pricing the asset or liability (if available), and not on our assumptions.  The identification of market participant assumptions provides a basis for determining what inputs are to be used for pricing each asset or liability.  SFAS 157 also establishes a three-level fair value hierarchy, reflecting the extent to which inputs to the determination of fair value can be observed, and requires fair value disclosures based upon this hierarchy.  The adoption of SFAS 157 did not have a material impact on our financial position, results of operations and cash flows.  See Note 5 - Fair Value for additional information.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities ("SFAS 159").  SFAS 159 establishes a fair value option under which entities can elect to report certain financial assets and liabilities at fair value, with changes in fair value recognized in earnings.  On January 1, 2008, SFAS 159 became effective; however, we did not elect the fair value option for any of our financial assets or liabilities.

Pension and Postretirement:We adopted the recognition and disclosure provisions of SFAS No. 158 Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R) ("SFAS 158") as of December 31, 2006.  SFAS 158 requires companies to measure plan assets and benefit obligations as of the same date as their fiscal year-end balance sheet.  This provision of SFAS 158 is effective for CVPS in 2008 and we adopted the measurement provisions on January 1, 2008.  For the purpose of determining the impact of adoption, we estimated that changing the annual benefit measurement date from September 30, 2007 to December 31, 2008 resulted in a pre-tax charge of $1.3 million, of which $0.1 million was recorded to retained earnings.  Our pension and postretirement medical plans will be remeasured as of December 31, 2008.  In our most recent retail rate proceeding we received approval for recovery of the regulated utility portion of the impact resulting from the change in measurement date.  Accordingly, we have recorded a regulatory asset of $1.2 million in the first quarter of 2008 that will be amortized over five years, commencing on February 1, 2008.

FSP FIN 39-1:In April 2007, the FASB issued FSP FIN 39-1, Offsetting of Amounts Related to Certain Contracts.  It permits the offsetting of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement that have been offset.  We adopted this FSP on January 1, 2008 and it did not impact our financial statements since our accounting policy is to continue reporting derivatives on a gross basis.

Recent Accounting Pronouncements Not Yet Adopted 

SFAS 141R:  In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations ("SFAS 141R").  SFAS 141R replaces SFAS 141 and establishes principles and requirements for the recognition and measurement by acquirers of assets acquired, the liabilities assumed, any noncontrolling interest in the acquiree and any goodwill acquired.  SFAS 141R also establishes disclosure requirements to enable financial statement readers to evaluate the nature and financial effects of the business combination.  SFAS 141R will become effective for us on January 1, 2009.  The impact of applying SFAS 141R for periods subsequent to implementation will be dependent upon the nature of any transactions within the scope of SFAS 141R.

Page 9 of 33

SFAS 160:  In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51 ("SFAS 160").  SFAS 160 states that minority interests will be recharacterized as noncontrolling interests and classified as a component of equity.  SFAS 160 also establishes reporting requirements that provide sufficient disclosures that identify and distinguish between the interests of the parent and the interests of the noncontrolling owners.  SFAS 160 will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary.  It requires that once a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary be initially measured at fair value.  SFAS 160 is effective as of the beginning of an entity's first fiscal year beginning on or after December 15, 2008 (beginning January 1, 2009 for us).  We have not yet evaluated the impact, if any, that the adoption of SFAS 160 may have on our financial statements.

SFAS 161:  In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 ("SFAS 161").  SFAS 161 requires enhanced disclosures about an entity's derivative and hedging activities.  SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008 (beginning January 1, 2009 for us).  We have not yet evaluated the impact, if any, that the adoption of SFAS 161 may have on our disclosures.

SFAS 162:  In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles ("SFAS 162").  SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presently in conformity with U.S. GAAP ("the GAAP hierarchy").  SFAS 162 is effective 60 days following the SEC's approval of the Public Company Accounting Oversight Board amendments to AU Section 411, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.  We have not yet evaluated the impact, if any, that the adoption of SFAS 162 may have on our financial statements.

NOTE 2 - EARNINGS PER SHARE ("EPS")

The Condensed Consolidated Statements of Income include basic and diluted per share information.  The table below provides a reconciliation of the numerator and denominator used in calculating basic and diluted EPS (dollars in thousands):

	Three months ended June 30				Six months ended June 30
	2008		2007		2008		2007
Numerator for basic and diluted EPS:
Net income	$	4,001	$	521	$	9,909	$	6,227
Dividends declared on preferred stock		92		92		184		184
Net income available for common stock	$	3,909	$	429	$	9,725	$	6,043
Denominators for basic and diluted EPS:
Weighted-average basic shares of common stock outstanding		10,337,893		10,186,907		10,306,699		10,161,336
Dilutive effect of stock options		46,256		104,636		69,393		182,437
Dilutive effect of performance shares		13,526		15,552		11,197		12,217
Weighted-average diluted shares of common stock outstanding		10,397,675		10,307,095		10,387,289		10,355,990

All outstanding stock options were included in the computation of diluted shares for the second quarter and first six months 2008 and 2007 because the exercise prices were below the average market price of the common shares.  A total of 12,159 performance shares were excluded from the computation in the second quarter and first six months of 2008 because they are antidilutive.

Page 10 of 33

NOTE 3 - INVESTMENTS IN AFFILIATES

Summarized financial information for VELCO consolidated follows (dollars in thousands):

	Three months ended June 30						Six months ended June 30
	2008			2007			2008			2007
Operating revenues	$	18,599		$	12,310		$	36,473		$	25,097
Operating income	$	9,073		$	5,404		$	17,682		$	10,492
Net income before non-controlling interest	$	8,329		$	3,087		$	16,668		$	6,261
Less members' non-controlling interest in net income		7,628			2,360			15,256			4,725
Net income	$	701		$	727		$	1,412		$	1,536
Ownership interest		47.05	%		47.05	%		47.05	%		47.05	%
Equity in net income	$	274		$	386		$	646		$	783

Summarized financial information for Transco, also included in VELCO consolidated financial information above, follows (dollars in thousands):

	Three months ended June 30						Six months ended June 30
	2008			2007			2008			2007
Operating revenues	$	18,473		$	12,221		$	36,220		$	24,885
Operating income	$	9,522		$	5,747		$	18,580		$	11,287
Net income	$	8,767		$	3,393		$	17,534		$	6,900
Ownership interest		39.79	%		29.86	%		39.79	%		29.86	%
Equity in net income	$	3,675		$	1,082		$	7,407		$	2,243

Included in Transco's operating revenues above are transmission sales to us of approximately $4 million in the second quarter and $7.4 million in the first six months of 2008 and $1.4 million in the second quarter and $2.9 million in the first six months of 2007.  These amounts are reflected as Transmission - affiliates on our Condensed Consolidated Statements of Income.  Transmission services provided by Transco are billed to us under the 1991 Transmission Agreement ("VTA").  All Vermont electric utilities are parties to the VTA.  In June 2007, FERC issued an Order combining three FERC filings related to the VTA, including a request by five municipal utilities for FERC approval to withdraw from the VTA and take transmission service under a different tariff, and a request by Transco for revisions to the VTA.  The parties reached a preliminary settlement in January 2008 and filed a definitive settlement agreement with the FERC in March 2008.  The settlement agreement is supported by all parties, including us, and resolves all issues that were raised in the FERC proceedings.  The settlement agreement must be approved by the FERC and related amendments to the Transco Operating Agreement, necessary to implement the settlement, must be approved by the PSB.  We expect that the settlement agreement, if approved, will trigger reconsideration events under FIN 46R, Consolidation of Variable Interest Entities, but we have not yet completed our assessment of the potential impact, if any.

Summarized financial information for VYNPC follows (dollars in thousands):

	Three months ended June 30						Six months ended June 30
	2008			2007			2008			2007
Operating revenues	$	45,140		$	31,920		$	90,794		$	76,292
Operating (loss) income	$	(137	)	$	1,005		$	2		$	1,832
Net income	$	110		$	193		$	234		$	418
Ownership interest		58.85	%		58.85	%		58.85	%		58.85	%
Equity in net income	$	65		$	113		$	138		$	246

Page 11 of 33

Included in VYNPC's operating revenues above are sales to us of approximately $15.7 million in the second quarter and $31.6 million in the first six months of 2008 and $11.1 million in the second quarter and $26.6 million in the first six months of 2007.  These are included in Purchased power - affiliates on our Condensed Consolidated Statements of Income.  Also see Note 9 - Commitments and Contingencies.

Maine Yankee, Connecticut Yankee and Yankee Atomic We own, through equity investments, 2 percent of Maine Yankee, 2 percent of Connecticut Yankee and 3.5 percent of Yankee Atomic.  All three companies have completed plant decommissioning and the operating licenses have been amended by the Nuclear Regulatory Commission ("NRC") for operation of Independent Spent Fuel Storage Installations.  All three remain responsible for safe storage of the spent nuclear fuel and waste at the sites until the United States Department of Energy ("DOE") meets its obligation to remove the material from the sites.  Our shares of their estimated costs are reflected on the Condensed Consolidated Balance Sheets as regulatory assets and nuclear decommissioning liabilities (current and non-current).  These amounts are adjusted when revised estimates are provided.  At June 30, 2008, we had regulatory assets of $1.5 million for Maine Yankee, $6.6 million for Connecticut Yankee and $2.7 million for Yankee Atomic.  These estimated costs are being collected from customers through existing retail rate tariffs.  Total billings from the three companies amounted to $0.5 million in the second quarter and $1.1 million in the first six months of 2008 and $0.7 million in the second quarter and $1.4 million in the first six months of 2007.  These amounts are included in Purchased power - affiliates on our Condensed Consolidated Statements of Income.

All three companies have been seeking recovery of fuel storage-related costs stemming from the default of the DOE under the 1983 fuel disposal contracts that were mandated by the United States Congress under the Nuclear Waste Policy Act of 1982.  Under the Act, the companies believe the DOE was required to begin removing spent nuclear fuel and Greater than Class C material from the nuclear plants no later than January 31, 1998 in return for payments by each company into the nuclear waste fund.  No fuel has been collected by the DOE, and spent nuclear fuel is being stored at each of the plants.  Maine Yankee, Connecticut Yankee and Yankee Atomic collected the funds from us and other wholesale utility customers, under FERC-approved wholesale rates, and our share of these payments was collected from retail customers.

In 2006, the United States Court of Federal Claims issued judgment in the spent fuel litigation.  Maine Yankee was awarded $75.8 million in damages through 2002, Connecticut Yankee was awarded $34.2 million through 2001 and Yankee Atomic was awarded $32.9 million through 2001.  In December 2006, the DOE filed a notice of appeal of the court's decision and all three companies filed notices of cross appeals.  As a result, none of the companies have recognized the damage awards on their books.  A decision on the appeals is expected in late 2008.  Each of the companies' respective FERC settlements requires that damage payments, net of taxes and net of further spent fuel trust funding, be credited to ratepayers including us.  We expect that our share of these awards, if any, would be credited to our ratepayers.

In December 2007, the three companies filed a second round of claims against the government for damages sustained from 2002 for Maine Yankee and from 2001 for Connecticut Yankee and Yankee Atomic.

We cannot predict the ultimate outcome of these cases due to the pending appeals and the complexity of the issues in the second round of cases.

NOTE 4 - RETAIL RATES AND REGULATORY ACCOUNTING

Retail Rates In January 2008, the PSB approved a settlement agreement that we previously reached with the Vermont Department of Public Service ("DPS").  The settlement included, among other things, a 2.30 percent rate increase (additional revenue of $6.4 million on an annual basis) effective February 1, 2008 and a 10.71 percent rate of return on equity, capped until our next rate proceeding or approval of the alternative regulation plan that we submitted in August 2007.  We also agreed to conduct an independent business process review to assure our cost controls are sufficiently challenging and that we are operating efficiently.  That review commenced in April 2008 and is expected to conclude in the third quarter of 2008.

The alternative regulation plan proposal that we submitted in August 2007 for PSB approval is currently under review and a PSB decision is expected in the fourth quarter of 2008.  If approved, our alternative regulation plan allows for quarterly rate adjustments to reflect power supply cost changes and annual rate adjustments to reflect changes, within predetermined limits, from the allowed earnings level.  The plan is designed to encourage efficiency in operations, and would replace the traditional ratemaking process.  We cannot predict the outcome of this matter at this time.

Page 12 of 33

Regulatory Accounting Under SFAS 71, we account for certain transactions in accordance with permitted regulatory treatment whereby regulators may permit incurred costs, typically treated as expenses by unregulated entities, to be deferred and expensed in future periods when recovered in future revenues.  In the event that we no longer meet the criteria under SFAS 71 and there is not a rate mechanism to recover these costs, we would be required to write off $16.1 million of regulatory assets (total regulatory assets of $30.6 million less pension and postretirement medical costs of $14.5 million), $18.7 million of other deferred charges - regulatory and $11.3 million of other deferred credits - regulatory.  This would result in a total extraordinary charge to operations of $23.5 million pre-tax as of June 30, 2008.  We would be required to record pre-tax pension and postretirement costs of $13.4 million to Accumulated Other Comprehensive Loss and $1.1 million to Retained Earnings as reductions to stockholders' equity.  We would also be required to determine any potential impairment to the carrying costs of deregulated plant.

All regulatory assets are being recovered in retail rates and are earning a return except for income taxes, nuclear plant dismantling costs and pension and postretirement medical costs.  Regulatory assets, certain other deferred charges and other deferred credits are shown in the table below (dollars in thousands).

	June 30, 2008		December 31, 2007
Regulatory assets
Pension and postretirement medical costs - SFAS 158	$	14,498	$	14,673
Nuclear plant dismantling costs		10,773		11,889
Nuclear refueling outage costs - Millstone Unit #3		273		820
Income taxes		3,944		3,757
Asset retirement obligations and other		1,160		849
Total Regulatory assets		30,648		31,988
Other deferred charges - regulatory
Vermont Yankee sale costs (tax)		673		673
Unrealized losses on power-related derivatives		17,195		7,817
Other		830		498
Total Other deferred charges - regulatory		18,698		8,988
Other deferred credits - regulatory
Asset retirement obligation - Millstone Unit #3		2,880		3,085
Vermont Yankee related deferrals		1,093		1,596
Emission allowances and renewable energy credits		462		616
Unrealized gains on power-related derivatives		3,235		707
Environmental remediation		1,462		1,834
Other		2,205		1,557
Total Other deferred credits - regulatory	$	11,337	$	9,395

NOTE 5 - FAIR VALUE

Effective January 1, 2008, we adopted SFAS 157 as required.  SFAS 157 establishes a single, authoritative definition of fair value, prescribes methods for measuring fair value, establishes a fair value hierarchy based on the inputs used to measure fair value and expands disclosures about the use of fair value measurements; however, SFAS 157 does not expand the use of fair value accounting in any new circumstances.  SFAS 157 defines fair value as "the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date."

Valuation Techniques SFAS 157 emphasizes that fair value is not an entity-specific measurement but a market-based measurement utilizing assumptions market participants would use to price the asset or liability.  SFAS 157 provides guidance on three valuation techniques to be used at initial recognition and subsequent measurement of an asset or liability:

Page 13 of 33

Market Approach:  This approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

Income Approach:  This approach uses valuation techniques to convert future amounts (cash flows, earnings) to a single present value amount.

Cost Approach:  This approach is based on the amount currently required to replace the service capacity of an asset (often referred to as the “current replacement cost”).

The valuation technique (or a combination of valuation techniques) utilized to measure fair value is the one that is appropriate given the circumstances and for which sufficient data is available.  Techniques must be consistently applied, but change is appropriate if new information is available.

Fair Value Hierarchy SFAS 157 establishes a fair value hierarchy (“hierarchy”) to prioritize the inputs used in valuation techniques. The hierarchy is designed to indicate the relative reliability of the fair value measure. The highest priority is given to quoted prices in active markets, and the lowest to unobservable data, such as an entity’s internal information. The lower the level of the input of a fair value measurement, the more extensive the disclosure requirements. There are three broad levels:

Level 1:  Quoted prices (unadjusted) are available in active markets for identical assets or liabilities as of the reporting date.

Level 2:  Pricing inputs are other than quoted prices in active markets included in Level 1, which are directly or indirectly observable as of the reporting date.  This value is based on other observable inputs, including quoted prices for similar assets and liabilities in markets that are not active.  Level 2 includes investments in our Millstone Decommissioning Trust Funds such as fixed income securities (Treasury securities, other agency and corporate debt) and equity securities.

Level 3:  Pricing inputs include significant inputs that are generally less observable.  Unobservable inputs may be used to measure the asset or liability where observable inputs are not available.  We develop these inputs based on the best information available, including our own data.  Level 3 instruments include derivatives related to our forward energy purchases and sales, financial transmission rights and a power-related option contract.

Recurring Measures The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis.  Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels (dollars in thousands):

	Fair Value as of June 30, 2008
	Level 1		Level 2		Level 3		Total
Assets:
Millstone decommissioning trust fund	$	0	$	5,513	$	0	$	5,513
Power-related derivatives - current		0		0		3,290		3,290
Total	$	0	$	5,513	$	3,290	$	8,803
Liabilities:
Power-related derivatives	$	0	$	0	$	17,195	$	17,195

Millstone Decommissioning Trust Our primary valuation technique to measure the fair value of our nuclear decommissioning trust investments is the market approach.  Actively traded quoted prices cannot be obtained for the funds in our decommissioning investments.  However, actively traded quoted prices for the underlying securities comprising the funds have been obtained.  Due to these observable inputs, fixed income, equity and cash equivalent securities in the funds are classified as Level 2.

Derivative Financial Instruments We estimate fair values of power-related derivatives based on the best market information available, including the use of internally developed models and broker quotes for forward energy contracts.  We use other models and our own assumptions about future congestion costs for valuing financial transmission rights.  We also use a binomial tree model and an internally developed long-term price forecast to value a power-related option contract.

Page 14 of 33

Level 3 Changes The following table is a reconciliation of changes in the net fair value of power-related derivatives which are classified as Level 3 in the fair value hierarchy.  There were no transfers in or out of Level 3 during the periods presented (dollars in thousands).

	Three months ended			Six months ended
Balance at Beginning of Period	$	(11,426	)	$	(7,110	)
Net realized gains recognized in Purchased Power - other		60			16
Net unrealized losses included in regulatory liability (asset)		(2,629	)		(7,550	)
Purchases, sales, issuances and net settlements		90			739
Transfers to or (from) level 3		0			0
Balance at June 30, 2008	$	(13,905	)	$	(13,905	)
Net realized gains relating to instruments still held during the period	$	56		$	33

Based on a PSB-approved Accounting Order, we record the change in fair value of power contract derivatives as deferred charges or deferred credits on the Condensed Consolidated Balance Sheet, depending on whether the fair value is an unrealized loss or gain.  The corresponding offsets are recorded as current and long-term assets or liabilities depending on the duration.

NOTE 6 - LONG-TERM DEBT

Long-term debt consists of the following (dollars in thousands):

	June 30, 2008		December 31, 2007
First Mortgage Bonds
6.27%, Series NN, due 2008	$	3,000	$	3,000
5.00%, Series SS, due 2011		20,000		20,000
5.72%, Series TT, due 2019		55,000		55,000
6.90%, Series OO, due 2023		17,500		17,500
6.83%, Series UU, due 2028		60,000		0
8.91%, Series JJ, due 2031		15,000		15,000
New Hampshire Industrial Development Authority Bonds
Variable 3.75%, due 2009		5,450		5,450
Total long-term debt		175,950		115,950
Less current amount payable, due within one year		3,000		3,000
Total long-term debt less current portion	$	172,950	$	112,950

On May 15, 2008, we issued $60 million of our First Mortgage 6.83% Bonds, Series UU due May 15, 2028.  The issuance was pursuant to our Indenture of Mortgage dated as of October 1, 1929, as amended and supplemented by supplemental indentures, including the Forty-Sixth Supplemental Indenture, dated May 1, 2008.  The Bonds were issued in a private placement in reliance on exemptions from registration under the Securities Act of 1933, as amended, pursuant to the terms of a Bond Purchase Agreement, dated May 15, 2008, among us and 10 institutional investors.  The bond issuance required prior approval by the PSB, which we received on April 23, 2008.   We used the proceeds of this offering to repay a $53 million short-term note and for other general corporate purposes.

Substantially all of our utility property and plant is subject to liens under our First Mortgage Bonds.  The First Mortgage Bonds are callable at our option at any time upon payment of a make-whole premium, calculated as the excess of the present value of the remaining scheduled payments to bondholders, discounted at a rate that is 0.5 percent higher than the comparable U.S. Treasury Bond yield, over the early redemption amount.

Page 15 of 33

Our debt financing documents do not contain cross-default provisions to affiliates outside of the consolidated entity.  Certain of our debt financing documents contain cross-default provisions to our wholly owned subsidiaries, East Barnet Hydroelectric, Inc., C.V. Realty, Inc. and Custom Investment Corporation.  These cross-default provisions generally relate to an inability to pay debt or debt acceleration, inappropriate affiliate transactions or the levy of significant judgments or attachments against our property. Scheduled sinking fund payments and maturities for the next five years are $3 million in 2008, $5.5 million in 2009, $0 in 2010, $20 million in 2011 and $0 in 2012.

Dividend and Optional Stock Redemption Restrictions:  We have a $25 million revolving credit facility that restricts optional redemptions of capital stock.  The First Mortgage Bond indenture and our Articles of Association also contain certain restrictions on the payment of cash dividends on and optional redemptions of all capital stock.  Under the most restrictive of these provisions, approximately $59.3 million of retained earnings was not subject to such restriction at June 30, 2008.  The Articles also restrict the payment of common dividends or purchase of any common shares if the common equity level falls below 25 percent of total capital, applicable only as long as Preferred Stock is outstanding.  Our Articles of Association also contain a covenant that requires us to maintain a minimum common equity level of approximately $3.3 million as long as any Preferred Stock is outstanding.

Covenants:  Our long-term debt indentures, letters of credit, and credit facility contain financial and non-financial covenants.  The most restrictive financial covenants include maximum debt to total capitalization of 65 percent, and minimum interest coverage of 2 times.  At June 30, 2008, we were in compliance with all covenants.

NOTE 7 - NOTES PAYABLE AND CREDIT FACILITY

Notes payable consists of the following (dollars in thousands):

	June 30, 2008		December 31, 2007
Revenue Bonds
Vermont Industrial Development Authority Bonds
Variable, due 2013 (1.65 % at June 30, 2008 and 3.05% at December 31, 2007)	$	5,800	$	5,800
Connecticut Development Authority Bonds
Variable, due 2015 (1.72% at June 30, 2008 and 3.55% at December 31, 2007)		5,000		5,000
Short term note payable
Variable, due June 30, 2008 (5.44% at December 31, 2007)		0		53,000
Total Notes Payable	$	10,800	$	63,800

Short-term note payable: On May 15, 2008, we used the proceeds from the issuance of First Mortgage Bonds as described in Note 6 - Long-Term Debt to repay in full a six-month unsecured note in the principal amount of $53 million.

Credit Facility: We have a 364-day, $25 million unsecured revolving credit facility with a lending institution pursuant to a Credit Agreement dated December 28, 2007.  At June 30, 2008 no amounts were outstanding under this facility, but two letters of credit totaling $6 million have been issued to support certain power-related performance assurance requirements as described in Note 9 - Commitments and Contingencies.

NOTE 8 - PENSION AND POSTRETIREMENT MEDICAL BENEFITS

The fair value of Pension Plan trust assets was $86.2 million at June 30, 2008 and $91.9 million at December 31, 2007. The unfunded accrued pension benefit obligation recorded on the Condensed Consolidated Balance Sheets was $0.2 million at June 30, 2008 and $1.7 million at December 31, 2007.

The fair value of Postretirement Plan trust assets was $14.2 million at June 30, 2008 and $13.2 million at December 31, 2007.  The unfunded accrued postretirement benefit obligation recorded on the Condensed Consolidated Balance Sheets was $10.2 million at June 30, 2008, and $13 million at December 31, 2007.

In June 2008, we contributed $3.1 million to the pension trust fund and $3.1 million to the postretirement medical trust funds.  We do not plan to make any additional contributions to these trust funds in 2008.  In June 2007, we contributed $4.1 million to the pension trust fund and $2.5 million to the postretirement medical trust funds.

Page 16 of 33

Components of net periodic benefit costs follow (dollars in thousands):

	Three months ended June 30						Six months ended June 30
Pension Benefits	2008			2007			2008			2007
Service cost	$	823		$	888		$	1,646		$	1,776
Interest cost		1,523			1,561			3,046			3,122
Expected return on plan assets		(1,831	)		(1,680	)		(3,662	)		(3,360	)
Amortization of net actuarial loss		-			146			-			292
Amortization of prior service cost		97			100			194			200
Net periodic benefit cost		612			1,015			1,224			2,030
Less amounts capitalized		100			181			188			352
Net benefit costs expensed	$	512		$	834		$	1,036		$	1,678
Postretirement Benefits
Service cost	$	155		$	145		$	310		$	290
Interest cost		403			377			806			754
Expected return on plan assets		(267	)		(233	)		(534	)		(466	)
Amortization of net actuarial loss		263			263			526			526
Amortization of transition obligation		64			64			128			128
Net periodic benefit cost		618			616			1,236			1,232
Less amounts capitalized		101			110			190			214
Net benefit costs expensed	$	517		$	506		$	1,046		$	1,018

NOTE 9 - COMMITMENTS AND CONTINGENCIES

Nuclear Decommissioning Obligations We have a 1.7303 joint-ownership percentage in Millstone Unit # 3, in which Dominion Nuclear Connecticut ("DNC") is the lead owner with 93.4707 percent of the plant joint-ownership.  We have an external trust dedicated to funding our joint-ownership share of future decommissioning costs.  DNC has suspended contributions to the Millstone Unit #3 Trust Fund because the minimum NRC funding requirements are being met or exceeded.  We have also suspended contributions to the Trust Fund, but could choose to renew funding at our own discretion as long as the minimum requirement is met or exceeded.  If additional decommissioning funding is necessary, we will be obligated to resume contributions to the Trust Fund.

Our obligations related to Maine Yankee, Connecticut Yankee and Yankee Atomic are described in Note 3 - Investments in Affiliates.  We also had a 35 percent ownership interest in the Vermont Yankee nuclear power plant through our equity investment in VYNPC, but the plant was sold in 2002.  Our obligation for plant decommissioning costs ended when the plant was sold, except that VYNPC retained responsibility for the pre-1983 spent fuel disposal cost liability.  VYNPC has a dedicated trust fund for this liability.  At this time, the fund balance is expected to equal or exceed the obligation.  Excess funds, if any, will be returned to us and must be applied to the benefit of ratepayers.

Long-Term Power Purchase Obligations Vermont Yankee:We are purchasing our entitlement share of Vermont Yankee plant output through the Purchase Power Agreement ("PPA") between Entergy Nuclear Vermont Yankee, LLC ("ENVY") and VYNPC.  An uprate in 2006 increased the plant's operating capacity by approximately 20 percent. After completion of the uprate, VYNPC's entitlement to plant output declined from 100 percent to 83 percent, and our entitlement share declined from 35 percent to 29 percent. Therefore our nominal entitlement continues to be approximately 180 MW.  ENVY has no obligation to supply energy to VYNPC over its entitlement share of plant output, so we receive reduced amounts when the plant is operating at a reduced level, and no energy when the plant is not operating.  The plant normally shuts down for approximately one month every 18 months for maintenance and to insert new fuel into the reactor.

We normally purchase replacement energy in the wholesale markets in New England when the Vermont Yankee plant is not operating or is operating at reduced levels.  We also have forced outage insurance to cover additional costs, if any, of obtaining replacement power from other sources if the Vermont Yankee plant experiences unplanned outages.  In the first quarter of 2008, we renegotiated the policy to extend coverage through March 31, 2009 instead of December 31, 2008.  The coverage applies to unplanned outages of up to 30 consecutive calendar days per outage event, and provides for payment of the difference between the spot market price and $40/mWh. The total maximum coverage is $12 million.

Page 17 of 33

We are a party to a PSB Docket that was opened in June 2006 to investigate whether the reliability of the increased plant output would be adversely affected by the operation of the plant's steam dryer.  In September 2006, the PSB issued an order requiring ENVY to provide additional ratepayer protections.  The DPS and ENVY reached an agreement in a compliance filing with the PSB, but ENVY requested reconsideration of the PSB ruling.  Reconsideration was denied and ENVY appealed to the Vermont Supreme Court.  By Order entered July 10, 2008, the Vermont Supreme Court dismissed the appeal as moot, because the period during which the protection applied expired without occurrence of such an event.

The PPA between ENVY and VYNPC contains a formula for determining the VYNPC power entitlement following the uprate.  VYNPC and ENVY are seeking to resolve certain differences in the interpretation of the formula.  At issue is how much capacity and energy VYNPC Sponsors receive under the PPA following the uprate.  Based on VYNPC's calculations, the VYNPC Sponsors should be entitled to slightly more capacity and energy than they are currently receiving under the PPA.  We cannot predict the outcome of this matter at this time.

If the Vermont Yankee plant is shut down for any reason prior to the end of its operating license, we would lose the economic benefit of an energy volume equal to close to 50 percent of our total committed supply and have to acquire replacement power resources for approximately 40 percent of our estimated power supply needs.  Based on projected market prices as of June 30, 2008, the incremental replacement cost of lost power, including capacity, is estimated to average $84 million annually.  This estimate is based on projected market prices at a point in time and therefore can change significantly depending on market price volatility.  We are not able to predict whether there will be an early shutdown of the Vermont Yankee plant or whether the PSB would allow timely and full recovery of increased costs related to any such shutdown.  However, an early shutdown could materially impact our financial position and future results of operations if the costs are not recovered in retail rates in a timely fashion.

Hydro-Quebec: We are purchasing power from Hydro-Quebec under the Vermont Joint Owners ("VJO") Power Contract and related contracts negotiated between us and Hydro-Quebec.  There are specific contractual provisions that provide that in the event any VJO participant fails to meet its obligation under the contract, the remaining VJO participants must "step-up" to the defaulting party's share on a pro rata basis.  The VJO contract runs through 2020, but our purchases end in 2016.  As of November 1, 2007, the annual load factor was reduced from 80 percent to 75 percent, and it will remain at 75 percent until the contract ends, unless the contract is changed or there is a reduction due to the adverse hydraulic conditions described below.  Total purchases under the VJO Contract were $15.2 million in the second quarter and $31.6 in the first six months of 2008 and $15.9 million in the second quarter and $32.7 in the first six months of 2007.

In the early phase of the VJO Power Contract, two sellback contracts were negotiated, the first delaying the purchase of 25 MW of capacity and associated energy, the second reducing the net purchase of Hydro-Quebec power through 1996. In 1994, we negotiated a third sellback arrangement whereby we received a reduction in capacity costs from 1995 to 1999.  In exchange, Hydro-Quebec obtained two options.  The first gives Hydro-Quebec the right, upon four years' written notice, to reduce capacity and associated energy deliveries by 50 MW, including the use of a like amount of our Phase I/II transmission facility rights.  The second gives Hydro-Quebec the right, upon one year's written notice, to curtail energy deliveries in a contract year (12 months beginning November 1) from an annual capacity factor of 75 to 50 percent due to adverse hydraulic conditions as measured at certain metering stations on unregulated rivers in Quebec.  This second option can be exercised five times through October 2015.  Hydro-Quebec has not yet exercised these options.

In accordance with FIN 45, we are required to disclose the "maximum potential amount of future payments (undiscounted) the guarantor could be required to make under the guarantee."  Such disclosure is required even if the likelihood is remote.  With regard to the "step-up" provision in the VJO Power Contract, we must assume that all members of the VJO simultaneously default in order to estimate the "maximum potential" amount of future payments.  We believe this is a highly unlikely scenario given that the majority of VJO members are regulated utilities with regulated cost recovery.  Each VJO participant has received regulatory approval to recover the cost of this purchased power in their most recent rate applications.  Despite the remote chance that such an event could occur, we estimate that our undiscounted purchase obligation would be an additional $533 million for the remainder of the contract, assuming that all members of the VJO defaulted by July 1, 2008 and remained in default for the duration of the contract.  In such a scenario, we would then own the power and could seek to recover our costs from the defaulting members or our retail customers, or resell the power in the wholesale power markets in New England.  The range of outcomes (full cost recovery, potential loss or potential profit) would be highly dependent on Vermont regulation and wholesale market prices at the time.

Page 18 of 33

Independent Power Producers: We purchase power from a number of Independent Power Producers that own qualifying facilities under the Public Utility Regulatory Policies Act of 1978.  These qualifying facilities produce energy primarily using hydroelectric and biomass generation.  Most of the power comes through a state-appointed purchasing agent that allocates power to all Vermont utilities under PSB rules.  Total purchases were $7.1 million in the second quarter and $15 million in the first six months of 2008 and $6.2 million in the second quarter and $12.4 million in the first six months of 2007.

Performance Assurance We are subject to performance assurance requirements through ISO-New England under the Financial Assurance Policy for NEPOOL members.  We are required to post collateral for all net purchased power transactions since our credit limit with ISO-New England is zero.  Additionally, we are selling power in the wholesale market pursuant to contracts with third parties, and are required to post collateral under certain conditions defined in the contracts.  At June 30, 2008, our total collateral requirements amounted to $4.1 million.  We posted $6 million of letters of credit under our $25 million revolving credit facility and $0.7 million in cash to support these requirements.  The cash is included in Special Deposits on the Condensed Consolidated Balance Sheet.

We are also subject to performance assurance requirements under our Vermont Yankee power purchase contract (the 2001 Amendatory Agreement).  If ENVY, the seller, has commercially reasonable grounds to question our ability to pay for our monthly power purchases, ENVY may ask VYNPC and VYNPC may then ask us to provide adequate financial assurance of payment. We have not had to post collateral under this contract.

Operating leases We lease our vehicles and related equipment under one operating lease agreement.  We have guaranteed a residual value to the lessor in the event leased items are sold. The guarantee provides for reimbursement of up to 87 percent of the unamortized value of the lease portfolio.  Under the guarantee, if the entire lease portfolio had a fair value of zero at June 30, 2008, we would have been responsible for a maximum reimbursement of $8.1 million.  At June 30, 2008, we had a liability of $0.2 million, which is offset in prepayments on the Condensed Consolidated Balance Sheet.

Environmental Overthe years, more than 100 companies have merged into or been acquired by CVPS.  At least two of those companies used coal to produce gas for retail sale.  This practice ended more than 50 years ago.  Gas manufacturers, their predecessors and CVPS used waste disposal methods that were legal and acceptable then, but may not meet modern environmental standards and could represent a liability.  Some operations and activities are inspected and supervised by federal and state authorities, including the Environmental Protection Agency.  We believe that we are in compliance with all laws and regulations and have implemented procedures and controls to assess and assure compliance.  Corrective action is taken when necessary.  Below is a brief discussion of known material issues.

Cleveland Avenue Property: The Cleveland Avenue property in Rutland, Vermont, was used by a predecessor to make gas from coal.  Later, we sited various operations there.  Due to the existence of coal tar deposits, polychlorinated biphenyl contamination and the potential for off-site migration, we conducted studies in the late 1980s and early 1990s to quantify the potential costs to remediate the site.  Investigation at the site has continued, including work with the State of Vermont to develop a mutually acceptable solution.  In 2006, we updated the cost estimate of remediation for this site.  The liability for site remediation is expected to range from $0.9 million to $2.3 million.  As of June 30, 2008, we accrued $1.3 million representing the most likely cost of the remediation effort.

Brattleboro Manufactured Gas Facility: In the 1940s, we owned and operated a manufactured gas facility in Brattleboro, Vermont.  We ordered a site assessment in 1999 at the request of the State of New Hampshire.  In 2001, New Hampshire indicated that no further action was required, though it reserved the right to require further investigation or remedial measures.  In 2002, the Vermont Agency of Natural Resources notified us that our corrective action plan for the site was approved.  That plan is now in place.  In 2006, we updated the cost estimate of remediation for this site.  The liability for site remediation is expected to range from $0.1 million to $1.3 million.  As of June 30, 2008, we accrued $0.6 million representing the most likely cost of the remediation effort.

Dover, New Hampshire, Manufactured Gas Facility: In 1999, Public Service Company of New Hampshire contacted us about this site, and we reached a settlement with them in 2002.  Our remaining obligation was less than $0.1 million at June 30, 2008.

The reserve for environmental matters described above amounted to $1.9 million as of June 30, 2008 and December 31, 2007.  The current and long-term portions are included as liabilities on the Condensed Consolidated Balance Sheets.  The reserve represents our best estimate of the cost to remedy issues at these sites based on available information as of the end of the reporting period.  To our knowledge, there is no pending or threatened litigation regarding other sites with the potential to cause material expense.  No government agency has sought funds from us for any other study or remediation.

Page 19 of 33

Reserve for Loss on Power Contract On January 1, 2004, we terminated a long-term power contract with Connecticut Valley Electric Company, a regulated electric utility that used to be our wholly owned subsidiary.  In accordance with the requirements of SFAS 5, Accounting for Contingencies, we recorded a $14.4 million pre-tax loss accrual in the first quarter of 2004 related to the contract termination.  The loss accrual represented our best estimate of the difference between expected future sales revenue in the wholesale market for the purchased power that was formerly sold to Connecticut Valley Electric Company and the net cost of purchased power obligations.  We review this estimate at the end of each reporting period and will increase the reserve if the revised estimate exceeds the recorded loss accrual.  The loss accrual is being amortized on a straight-line basis through 2015, the estimated life of the power contracts that were in place to supply power under the contract.  The reserve amounted to $9 million at June 30, 2008 and $9.6 million at December 31, 2007.  The current and long-term portions are included as liabilities on the Condensed Consolidated Balance Sheets.

Catamount Indemnifications In 2005 we sold our remaining interests in Catamount Energy Corporation ("Catamount"), our wholly owned subsidiary.  As part of the sale, we agreed to indemnify Catamount, the purchaser, its successors and assigns, and certain of the purchaser's affiliates, in respect of a breach of certain representations and warranties and covenants.  Indemnification is subject to a $1.5 million deductible and a $15 million cap, excluding certain customary items.  Environmental representations are subject to the deductible and the cap, and such environmental representations for only two of Catamount's underlying energy projects survived beyond June 30, 2007.  Our estimated "maximum potential" amount of future payments related to these indemnifications is limited to $15 million.  We have not recorded any liability related to these indemnifications.

NOTE 10 - SEGMENT REPORTING

The following table provides segment financial data (dollars in thousands).  Inter-segment revenues were a nominal amount in all periods presented.

					Reclassification &
			Other		Consolidating
	CV-VT		Companies		Entries			Consolidated
Three Months Ended
June 30, 2008
Revenues from external customers	$	84,487	$	434	$	(434	)	$	84,487
Net income	$	3,939	$	62	$	-		$	4,001
Total assets at June 30, 2008	$	555,422	$	1,965	$	(242	)	$	557,145
June 30, 2007
Revenues from external customers	$	77,380	$	439	$	(439	)	$	77,380
Net income	$	433	$	88	$	-		$	521
Total assets at December 31, 2007	$	538,481	$	2,134	$	(301	)	$	540,314
Six Months Ended
June 30, 2008
Revenues from external customers	$	175,711	$	866	$	(866	)	$	175,711
Net income	$	9,769	$	140	$	-		$	9,909
Total assets at June 30, 2008	$	555,422	$	1,965	$	(242	)	$	557,145
June 30, 2007
Revenues from external customers	$	164,076	$	874	$	(874	)	$	164,076
Net income	$	5,911	$	316	$	-		$	6,227
Total assets at December 31, 2007	$	538,481	$	2,134	$	(301	)	$	540,314

Page 20 of 33

Item 2.   Management's Discussion and Analysis of Financial Condition and Results of Operations

In this section we discuss our general financial condition and results of operations.  Certain factors that may impact future operations are also discussed.  Our discussion and analysis is based on, and should be read in conjunction with, the accompanying Condensed Consolidated Financial Statements.

Forward-looking statements Statements contained in this report that are not historical fact are forward-looking statements within the meaning of the 'safe-harbor' provisions of the Private Securities Litigation Reform Act of 1995.  Whenever used in this report, the words "estimate," "expect," "believe," or similar expressions are intended to identify such forward-looking statements.  Forward-looking statements involve estimates, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements.  Actual results will depend upon, among other things:

§	the actions of regulatory bodies with respect to allowed rates of return, continued recovery of regulatory assets and proposed alternative regulations;
§	performance and continued operation of the Vermont Yankee nuclear power plant;
§	effects of and changes in weather and economic conditions;
§	volatility in wholesale power markets;
§	our ability to maintain or improve our current credit ratings;
§	the operations of ISO-New England;
§	changes in the cost or availability of capital;
§	changes in financial or regulatory accounting principles or policies imposed by governing bodies;
§	capital market conditions, including price risk due to marketable securities held as investments in trust for nuclear decommissioning, pension and postretirement medical plans;
§	changes in the levels and timing of capital expenditures, including our discretionary future investments in Transco;
§	our ability to replace or renegotiate our long-term power supply contracts;
§	our ability to replace a mature workforce and retain qualified, skilled and experienced personnel; and
§	other presently unknown or unforeseen factors.

We cannot predict the outcome of any of these matters; accordingly, there can be no assurance as to actual results.  We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise.

EXECUTIVE SUMMARY

Our core business is the Vermont electric utility business.  The rates we charge for retail electricity sales are regulated by the Vermont Public Service Board ("PSB").  Fair regulatory treatment is fundamental to maintaining our financial stability.  Rates must be set at levels to recover costs, including a market rate of return to equity and debt holders, in order to attract capital.  As discussed below, under the heading Retail Rates and Alternative Regulation, we expect to have a decision in our alternative regulation filing in the fourth quarter of 2008.  The implementation of this plan will provide more timely adjustments to power, operating and maintenance costs, which will better serve the interests of customers and shareholders.

Our consolidated earnings for the second quarter were $4 million, or 38 cents per diluted share of common stock, and $9.9 million, or 94 cents per diluted share of common stock, for the first six months of 2008.  This compares to consolidated earnings of $0.5 million, or 4 cents per diluted share of common stock, for the second quarter and $6.2 million, or 58 cents per diluted share of common stock, for the first six months of 2007.  Higher average market prices on resale sales, equity in earnings from affiliates and lower storm restoration costs were the primary drivers of favorable results for both periods.  However, lower average usage by our retail customers reflecting a slowing economy and energy conservation and higher transmission expense have partially offset these favorable results.  The year-over-year earnings variances are described in more detail in Results of Operations below.

We continue to focus on key strategic financial initiatives including: restoring our corporate credit rating to investment-grade; ensuring that our retail rates are set at levels to recover our costs of service; evaluating financing options to support current and future working capital needs; and planning for replacement power when long-term power contracts begin to expire in 2012.

Page 21 of 33

In December 2007, we invested $53 million in Vermont Transco LLC ("Transco") using the proceeds from the issuance of a $53 million six-month unsecured note.  In May 2008, we issued $60 million of first mortgage bonds.  The proceeds were used to pay off the $53 million unsecured note and the remainder will be used for general corporate purposes.

RETAIL RATES AND ALTERNATIVE REGULATION

In January 2008, the PSB approved a settlement agreement that we reached with the Vermont Department of Public Service ("DPS").  This included, among other things, a 2.30 percent rate increase (additional revenue of $6.4 million on an annual basis) effective February 1, 2008 and a 10.71 percent rate of return on equity, capped until our next rate proceeding or approval of the alternative regulation plan that we submitted in August 2007.  We also agreed to conduct an independent business process review to assure our cost controls are sufficiently challenging and that we are operating efficiently.  That review commenced in April 2008, and is expected to conclude in the third quarter of 2008.

The alternative regulation plan proposal that we submitted in August 2007 for PSB approval is currently under review and a PSB decision is expected in the fourth quarter of 2008.  If approved, the plan would allow for quarterly rate adjustments to reflect power supply cost changes and annual rate adjustments to reflect changes, within predetermined limits, from the allowed earnings level.  The plan is designed to encourage efficiency in operations, and would replace the traditional ratemaking process, which is costly and time-consuming.  We cannot predict the outcome of the review at this time. We anticipate an additional rate change effective January 1, 2009 if our proposed plan is approved in its current form.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows At June 30, 2008, we had cash and cash equivalents of $6.6 million compared to $4.2 million at June 30, 2007.  The primary components of cash flows from operating, investing and financing activities for both periods are discussed in more detail below.

Operating Activities: Operating activities provided $15.9 million in the first six months of 2008.  Net income, when adjusted for depreciation, amortization, deferred income tax and other non-cash income and expense items, provided $18.8 million. This included $4.9 million of distributions received from affiliates, most materially from our investments in Transco.  In addition, changes in working capital and other items used $2.9 million.  This was primarily due to $7.2 million of employee benefit funding, including $6.2 million of pension and postretirement medical trust fund contributions, $1.2 million of income tax payments and $4.7 million of interest payments.

In the first six months of 2007 operating activities provided $8.6 million. Net income, when adjusted for depreciation, amortization, deferred income tax and other non-cash income and expense items, provided $15.9 million.  This included $2.5 million of distributions received from affiliates, most materially from our investments in Transco.  Changes in working capital and other items used $7.3 million.  This was primarily due to $7.9 million of employee benefit funding, including $6.6 million of pension and postretirement medical trust fund contributions, $5.1 million of income tax payments and $4 million of interest payments.  Special deposits and restricted cash used to meet performance assurance requirements for certain power contracts increased by $1.7 million because we replaced a $4.5 million letter of credit with cash and collateral requirements decreased.

Investing Activities: Investing activities used $15.8 million in the first six months of 2008, including $15.7 million for construction and plant expenditures and $0.1 million for other investments.  In the first six months of 2007, investing activities used $9.6 million, including $9.8 million for construction and plant expenditures, partially offset by $0.2 million from other investments.

Financing Activities: In the first six months of 2008, financing activities provided $2.7 million, including $60 million from proceeds of the issuance of first mortgage bonds, $1.5 million from stock option exercises and a $1 million reduction in special deposits for preferred stock sinking fund payments.  These items were partially offset by $53 million to repay notes payable, $4.9 million for dividends paid on common and preferred stock, $1 million for preferred stock sinking fund payments, $0.7 million for debt issuance costs, and $0.2 million for other financing activities.

During the first six months of 2007 financing activities provided $2.4 million, including $6.4 million from net borrowings under our revolving credit facility, $1 million from stock option exercises and a $1 million reduction in restricted cash for preferred stock sinking fund payments.  These items were partially offset by $4.9 million for dividends paid on common and preferred stock, $1 million for preferred stock sinking fund payments and $0.1 million for other financing activities.

Page 22 of 33

Financing 2008 Financing Activity: On May 15, 2008, we issued $60 million of our First Mortgage 6.83% Bonds, Series UU due May 15, 2028.   We used the proceeds of this offering to repay a $53 million note that was due on June 30, 2008.  We are evaluating other financing options to support current and future working capital needs resulting from investments in our distribution and transmission system and possible future investments in Transco.  Financing options that we are currently considering include increasing our unsecured revolving credit facility to $40 million by year end, and possibly offering equity of up to $25 million later in 2008 depending on market conditions.

Credit Facility: We have a 364-day, $25 million unsecured revolving credit facility with a major lending institution pursuant to a Credit Agreement dated December 28, 2007.  Pursuant to a commitment from the bank dated February 11, 2008, we have the sole option to extend the maturity of the credit facility to March 31, 2009.  The purpose of the facility is to provide liquidity for general corporate purposes, including working capital needs and power contract performance assurance requirements, in the form of funds borrowed and letters of credit.  In the first quarter of 2008, we obtained amendments to certain first mortgage bond issuance restrictions.  At June 30, 2008, there were no borrowings outstanding under this facility, but $6 million of letters of credit were outstanding in support of performance assurance requirements associated with our power transactions.

Covenants:  At June 30, 2008, we were in compliance with all financial and non-financial covenants related to our various debt agreements, articles of association, letters of credit and credit facility.

Investment opportunities in Transco Based on current projections, Transco expects to need additional capital in 2008 and 2009, but its projections are subject to change based on a number of factors, including revised construction estimates, timing of project approvals from regulators, and desired changes in its equity-to-debt ratio.  While we have no obligation to make additional investments in Transco, we continue to evaluate investment opportunities on a case-by-case basis.  Depending on timing, the factors discussed above, and the amounts invested by other owners, we could have an opportunity to make additional investments up to $6 million in 2008 and up to $21 million in 2009.  Any investments that we make in Transco are voluntary and subject to available capital and appropriate regulatory approvals.

Capital spending We expect to invest approximately $41.5 million in 2008 primarily in our transmission and distribution infrastructure to ensure continued system reliability, including installation of new voltage support equipment in southern Vermont currently estimated at $11 million.  This compares to capital expenditures of approximately $23 million in 2007.  These estimates are subject to continuing review and adjustment, and actual capital expenditures and timing may vary.  As of June 30, 2008 capital expenditures were $15.8 million.

Contractual obligations Our contractual obligations are described in Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2007 Annual Report on Form 10-K.  At June 30, 2008, contractual obligations did not change materially from December 31, 2007, except as summarized in the table below.

	Payments Due by Period (dollars in millions)
	Total		Less than 1 year (a)		1 - 3 years		3 - 5 years		After 5 years
Long-term debt	$	176.0	$	3.0	$	5.5	$	20.0	$	147.5
Interest on long-term debt	$	169.3	$	5.6	$	21.8	$	20.0	$	121.9
Notes payable (b)	$	10.8	$	0.0	$	0.0	$	0.0	$	10.8
Interest on notes payable (b)	$	2.3	$	0.2	$	0.7	$	0.7	$	0.7

(a)   Includes obligations for the six month period July 1, 2008 through December 31, 2008.

(b)   Includes two revenue bonds, one for $5.8 million due in 2013 and one for $5 million due in 2015.  The bonds are floating rate, monthly demand pollution-control bonds. The interest rates reset monthly and there is a remarketing feature if the bonds are put for redemption.  These bonds have historically been remarketed in the secondary market. The bonds are callable by the issuer on any business day.  Although the bonds are classified as current (payable within one year) under generally accepted accounting principles in the United States ("U. S. GAAP"), the bonds and related interest are shown in the table above as payments due on the due dates.

Page 23 of 33

Capitalization Our capitalization at June 30, 2008 was as follows:

	(dollars in millions)		Percent
Common stock equity	$	193.3		49	%
Preferred stock*		10.1		2	%
Long-term debt*		186.8		47	%
Capital lease obligations*		6.3		2	%
	$	396.5		100	%
* includes current portion

Performance assurance We are subject to performance assurance requirements through ISO-New England under the Financial Assurance Policy for NEPOOL members.  We are required to post collateral for all net purchased power transactions since our credit limit with ISO-New England is zero.  Additionally, we are selling power in the wholesale market pursuant to contracts with third parties, and are required to post collateral under certain conditions defined in the contracts.  At June 30, 2008, our total collateral requirements amounted to $4.1 million.  We posted $6 million of letters of credit and $0.7 million in cash to support these requirements.

We are also subject to performance assurance requirements under our Vermont Yankee power purchase contract (the 2001 Amendatory Agreement).  If Entergy Nuclear Vermont Yankee, LLC ("ENVY"), the seller, has commercially reasonable grounds to question our ability to pay for monthly power purchases, ENVY may ask VYNPC and VYNPC may then ask us to provide adequate financial assurance of payment. We have not had to post collateral under this contract.

Cash flow risks Based on our current cash forecasts, we will require outside capital in addition to cash flow from operations and our $25 million unsecured revolving credit facility in order to fund our business over the next year.  Although we issued first mortgage bonds in the second quarter of 2008, continued turbulence in the U. S. capital markets as described below could negatively impact our ability to obtain additional outside capital on reasonable terms.  In addition, an extended unplanned Vermont Yankee plant outage or similar event could have a significant effect on our liquidity due to the potentially high cost of replacement power and performance assurance requirements arising from purchases through ISO-New England or third parties.  In the event of an extended Vermont Yankee plant outage, we could seek emergency rate relief from our regulators.  Other material risks to cash flow from operations include: loss of retail sales revenue from unusual weather; slower-than-anticipated load growth and unfavorable economic conditions; increases in net power costs due to lower-than-anticipated margins on sales revenue from excess power or an unexpected power source interruption; required prepayments for power purchases; and increases in performance assurance requirements.

Impact of credit markets Due to market developments, including a series of rating agency downgrades of subprime U.S. mortgage-backed securities, the fair values of subprime-related investments have declined.  This decline in fair value has become especially problematic for certain large financial institutions.  However, we currently expect to have access to liquidity in the capital markets at reasonable rates.  We also have access to our unsecured revolving credit facility, which is not directly affected by general market conditions.  However, sustained turbulence in the U.S. credit markets could limit or delay our future access to capital.

We have reviewed our subprime exposure in our money market, benefit and nuclear decommissioning trust funds and have determined that a decline, if any, in fund fair value of subprime-related investments is not expected to be material.

ACCOUNTING MATTERS

Critical accounting policies and estimates  Our financial statements are prepared in accordance with U. S. GAAP, requiring us to make estimates and judgments that affect reported amounts of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of the Condensed Consolidated Financial Statements. Our critical accounting policies and estimates are described in Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2007 Annual Report on Form 10-K.  Changes to our critical accounting policies and estimates during 2008 are described below.

Page 24 of 33

Fair Value Measurements:  We adopted SFAS 157, Fair Value Measurements ("SFAS 157"), on January 1, 2008.  SFAS 157defines fair value, establishes criteria to be considered when measuring fair value and expands disclosures about fair value measurements, but it does not expand the use of fair value accounting in any new circumstances. On February 12, 2008, the FASB issued FASB Staff Position No. FAS 157-2, Effective Date of FASB Statement No. 157, which amends SFAS 157 by allowing entities to delay its effective date by one year for non-financial assets and non-financial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis.  We have deferred the application of SFAS 157 related to our asset retirement obligations until January 1, 2009, as permitted by this FSP.  Adoption of SFAS 157 did not have a material impact on our financial position, results of operations or cash flows.

SFAS 157 establishes a fair value hierarchy to prioritize the inputs used in valuation techniques. The hierarchy is designed to indicate the relative reliability of the fair value measure. The highest priority is given to quoted prices in active markets, and the lowest to unobservable data, such as an entity’s internal information. The lower the level of the input of a fair value measurement, the more extensive the disclosure requirements.  The three broad levels include: quoted prices in active markets for identical assets or liabilities (Level 1); significant other observable inputs (Level 2); and significant unobservable inputs (Level 3).

Our assets and liabilities that are recorded at fair value on a recurring basis include power-related derivatives and our Millstone decommissioning trust.  Power-related derivatives are classified as Level 3.  The Millstone decommissioning trust funds include treasury securities, other agency and corporate fixed income securities and equity securities that are classified as Level 2.  Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the SFAS 157 fair value hierarchy levels.  At June 30, 2008, the fair value of power-related derivatives was a net unrealized loss of $13.9 million, and the fair value of decommissioning trust assets was $5.5 million.  See Item 3 - Quantitative and Qualitative Disclosures About Market Risk for additional information about power-related derivatives.

Other See Note 1 - Business Organization and Summary of Significant Accounting Policies for a discussion of newly adopted accounting policies and recently issued accounting pronouncements.

RESULTS OF OPERATIONS

The following is a detailed discussion of the results of operations for the second quarter and first six months of 2008 compared to the same periods in 2007.  It should be read in conjunction with the condensed consolidated financial statements and accompanying notes included in this report.

Our second quarter 2008 earnings increased $3.5 million, or 34 cents per diluted share of common stock, compared to the same period in 2007.  Earnings for the first six months of 2008 increased $3.7 million, or 36 cents per diluted share of common stock, compared to the same period in 2007.  The table below provides a reconciliation of the primary year-over-year variances in diluted earnings per share.

	Three Months Ended			Six Months Ended
2007 Earnings per diluted share	$	0.04		$	0.58
Higher operating revenues		0.40			0.66
Higher equity in earnings of affiliates		0.21			0.27
Higher purchased power expense		(0.08	)		(0.12	)
Higher transmission expense		(0.15	)		(0.28	)
Lower (higher) other operating expenses		0.11			(0.02	)
Other		(0.15	)		(0.15	)
2008 Earnings per diluted share	$	0.38		$	0.94

Page 25 of 33

Operating Revenues Operating revenues and related mWh sales are summarized below.

	Three months ending June 30									Six months ending June 30
	Revenues (in thousands)					mWh Sales				Revenues (in thousands)						mWh Sales
	2008		2007			2008		2007		2008			2007			2008		2007
Residential	$	31,190	$	30,744			218,134		222,106	$	69,702		$	68,449			499,129		509,694
Commercial		26,051		25,615			206,747		209,137		52,850			52,763			426,498		433,809
Industrial		7,865		8,321			91,862		101,461		17,495			18,559			196,787		219,839
Other		467		462			1,579		1,570		932			912			3,149		3,107
Total Retail		65,573		65,142			518,322		534,274		140,979			140,683			1,125,563		1,166,449
Resale Sales		16,177		10,044			230,655		185,296		29,679			19,651			435,792		360,279
Provision for Rate Refund		-		(186	)		-		-		(62	)		(373	)		-		-
Other Operating Revenues		2,737		2,380			-		-		5,115			4,115			-		-
Total Operating Revenues	$	84,487	$	77,380			748,977		719,570	$	175,711		$	164,076			1,561,355		1,526,728

Operating revenues increased $7.1 million in the second quarter and $11.6 million in the first six months of 2008 compared to the same periods in 2007 primarily as a result of increased resale sales revenue.  The year-over-year variances are explained in more detail below.

§	Retail sales increased $0.4 million in the second quarter and $0.3 million in the first six months due to higher average retail rates, largely offset by lower sales volume.  This included: 1) an increase of $1.4 million in the second quarter and $2.6 million in the first six months due to a 2.30 percent rate increase effective February 1, 2008; 2) an increase of $0.6 million in the second quarter and $1.9 million in the first six months as a result of a higher average unit price due to customer usage mix; and 3) a decrease of $1.6 million in the second quarter and $4.2 million in the first six months due to a 3 percent and 3.5 percent decrease in sales volume for the respective periods.  The sales volume decrease reflects lower average usage resulting from a slowing economy and energy conservation, including the effect of the loss of three industrial customers due to plant closures.  Our business follows the economic cycles of the customers we serve.  Economic downturns typically lead to reductions in energy consumption and increased conservation measures.
§	Resale sales increased $6.1 million in the second quarter, including $3.7 million due to higher average prices and $2.4 million due to increased volume.  Resale sales increased $10 million in the first six months, including $5.9 million due to higher average prices and $4.1 million due to increased volume.  Resale sales were made at higher average prices in 2008 compared to 2007 due to more favorable prices on contract sales and overall higher market prices in ISO-New England.  We had more power available for resale in 2008 compared to 2007 due to second quarter 2007 scheduled refueling outages at Vermont Yankee and Millstone Unit #3 compared to nearly full production in 2008, and decreased retail sales volume.
§	The provision for rate refund, which is a reduction in operating revenues, is related to amounts that were included in retail rates in 2007 and January 2008 that were to be refunded to customers.  The provision for refund ended with new retail rates effective February 1, 2008 that include the customer refund.
§	Other operating revenues increased $0.4 million in the second quarter resulting from higher rates under our transmission tariffs and a $0.2 million favorable true-up under the tariffs.  Other operating revenues increased $1 million in the first six months for the same reasons and for the sales of additional transmission capacity from our share of Phase I/II transmission facility rights.  We began selling transmission capacity in April 2007, and we have the ability to restrict the amount of capacity assigned to the purchasers based on certain conditions.  Revenue from these sales amounted to approximately $1.4 million in calendar year 2007, and is estimated to be approximately $1.8 million annually from 2008 through 2010.

Page 26 of 33

Operating Expenses Operating expenses increased $3.8 million in the second quarter and $7.9 million in the first six months of 2008 compared to the same periods in 2007.  Significant variances in operating expenses on the Condensed Consolidated Statements of Income are described below.

Purchased Power: Purchased power expense and volume are summarized below.

	Three months ended June 30										Six months ended June 30
	Purchases										Purchases
	(in thousands)						mWh purchases				(in thousands)						mWh purchases
	2008			2007			2008		2007		2008			2007			2008		2007
VYNPC (a)	$	15,721		$	11,116			377,349		266,715	$	31,621		$	26,570			770,921		653,711
Hydro-Quebec		15,217			15,922			212,605		240,941		31,637			32,655			463,694		508,483
Independent Power Producers		7,137			6,169			54,926		49,156		15,041			12,355			111,232		93,800
Subtotal long-term contracts		38,075			33,207			644,880		556,812		78,299			71,580			1,345,847		1,255,994
Other purchases		2,992			7,075			22,572		98,528		4,736			9,844			39,098		130,245
SFAS No. 5 Loss amortizations		(299	)		(299	)		-		-		(598	)		(598	)		-		-
Nuclear decommissioning		549			701			-		-		1,117			1,385			-		-
Other		(35	)		(865	)		-		-		634			(132	)		-		-
Total purchased power	$	41,282		$	39,819			667,452		655,340	$	84,188		$	82,079			1,384,945		1,386,239

(a) Regulatory deferrals of less than $0.1 million in the second quarter and $0.5 million in the first six months of 2007 have been reclassified and included in Other to conform to current year presentation.

Purchased power increased $1.5 million in the second quarter and $2.1 million in the first six months of 2008 compared to the same periods in 2007 as a result of the following:

§	Purchases under long-term contracts increased $4.9 million in the second quarter and $6.7 million in the first six months compared to the same periods in 2007.  The increases for both periods largely resulted from purchases of our share of Vermont Yankee plant output.  The plant had a scheduled refueling outage during the second quarter of 2007 compared to nearly full production in 2008.  Higher output from Independent Power Producers, most of which are hydro facilities, was another source of increased purchased power during both periods.  These were partially offset by fewer scheduled deliveries from Hydro-Quebec because the annual load factor under the contract decreased from 80 percent to 75 percent beginning November 1, 2007.
§	Other purchases decreased $4.1 million in the second quarter and $5.1 million in the first six months largely due to replacement power purchases during the second quarter 2007 Vermont Yankee scheduled refueling outage.  We also had fewer short-term purchases in 2008 compared to 2007 because our retail load was less and we had more power available from Independent Power Producers and our owned generation.
§	Nuclear decommissioning costs are associated with our ownership interests in Maine Yankee, Connecticut Yankee and Yankee Atomic.  These costs are based on FERC-approved tariffs.  The costs decreased in the second quarter and first six months largely due to lower revenue requirements for Connecticut Yankee.
§	Other costs include net accounting deferrals and amortizations for Millstone Unit #3 scheduled refueling outages, and Vermont Yankee-related deferrals.  These deferrals and amortizations are based on PSB-approved regulatory accounting.  The increases in both periods largely resulted from deferred costs in the second quarter of 2007 for a scheduled refueling outage at Millstone Unit #3 versus amortizations in 2008.

Transmission - affiliates: These expenses represent our share of the net cost of service of Transco and some direct charges for facilities that we rent.  Transco allocates its monthly cost of service through the Vermont Transmission Agreement ("VTA"), net of NEPOOL Open Access Transmission Tariff ("NOATT") reimbursements and certain direct charges.  The NOATT is the mechanism through which the costs of New England's high-voltage transmission facilities are collected from load-serving entities using the system and redistributed to the owners of the facilities, including Transco.  Transmission - affiliates increased $2.6 million in the second quarter and $4.5 million in the first six months of 2008, primarily due to higher charges under the VTA resulting from Transco's capital projects, higher administrative and general costs, and lower NOATT reimbursements in the second quarter due to lower network loads.

Page 27 of 33

Other operation:  These expenses are related to operating activities such as customer accounting, customer service, administrative and general activities, regulatory deferrals and amortizations, and other operating costs incurred to support our core business.  Other operation increased $0.1 million in the second quarter and $1 million, or 3.8 percent, in the first six months.  The $1 million increase primarily resulted from the following:

§   Employee-related benefits increased $0.4 million, including a $0.9 million increase in active medical costs based on an increase in expected claims, a $0.3 million increase in reserves for workers' compensation claims and other benefit costs, partially offset by a $0.8 million decrease in pension costs resulting from lower service and interest costs and higher expected return on assets as of the September 30, 2007 measurement period.

§   Net regulatory amortizations increased $0.3 million largely due to amortization of certain regulatory assets based on retail rates effective February 1, 2008.

§   Reserve for uncollectible accounts increased $0.1 million resulting from a $0.6 million increase in 2008 largely driven by economic conditions, offset by a $0.5 million write off in 2007 for one large customer.

§   Other miscellaneous offsetting items increased $0.2 million.

Maintenance:  These expenses are associated with maintaining our electric distribution system and include costs of our jointly owned generating and transmission facilities.  Maintenance expenses decreased $2 million in the second quarter and $1.3 million in the first six months of 2008, principally due to storm restoration costs which decreased $3.1 million in the second quarter and $2.6 million in the first six months.  There were three major storms during the first six months of 2008 with one in the second quarter, compared to two major storms during the same period in 2007 with one in the second quarter.  The second quarter 2007 storm was the largest in the company's history and resulted in incremental storm restoration costs of approximately $3.3 million.  These decreases were partially offset by increased tree trimming expense of approximately $0.8 million in the second quarter and $0.9 million in first six months, primarily due to planned increases in tree trimming and more resources available for these activities in 2008.

Income tax expense (benefit): Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences, tax credits, tax settlements and changes in valuation allowances for the periods discussed herein.

Other Income Significant variances in income statement line items that comprise other income on the Condensed Consolidated Statements of Income are described below.

Equity in earnings of affiliates:  These earnings increased $2.4 million in the second quarter and $4.9 million in the first six months of 2008 largely due to increased earnings from our investments in Transco.  This is primarily due to Transco's increased investment base resulting from capital projects funded by additional investments made by Vermont utilities in December 2007, including our equity contribution of $53 million.

Other deductions:  Other deductions increased $0.4 million in the second quarter and $1.1 million in the first six months of 2008, primarily resulting from a decline in the cash surrender value of variable life insurance policies in trust to fund a supplemental employee retirement plan.  These variable life insurance policies are affected by changes in the equity market.  We have estimated that a 10 percent decrease in the equity markets supporting these policies could further decrease the cash surrender value by $0.5 million, and a 10 percent increase could increase it by the same amount.

Income tax expense:  Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences, tax credits, tax settlements and changes in valuation allowances for the periods discussed herein.

Interest ExpenseSignificant variances in income statement line items that comprise interest expense on the Condensed Consolidated Statements of Income are described below.

Interest on long-term debt:  These expenses increased $0.4 million in the second quarter and $0.5 million in the first six months of 2008 largely due to interest on the $60 million first mortgage bonds that we issued in May 2008.

Other interest:  These expenses increased $0.3 million in the second quarter and $0.9 million in the first six months principally due to interest and amortization of issuance costs associated with the $53 million short-term note.  We paid the note in full in May 2008.

Page 28 of 33

POWER SUPPLY MATTERS

Power Supply Management:  Our power supply portfolio includes a mix of base load and dispatchable resources.  These sources are used to serve our retail electric load requirements plus any wholesale obligations into which we enter.  Our goal is to manage our power supply portfolio by optimizing the use of these resources, and through wholesale sales and purchases to create a balance between our power supplies and load obligations.

Our current power forecast shows energy purchase and production amounts in excess of load obligations through 2011.  Due to the forecasted excess, we enter into fixed-price forward sale transactions to reduce price (revenue) volatility in order to help stabilize our net power costs.  Our main supply risk is with Vermont Yankee, and we have outage insurance through March 2009 to mitigate the market price risk during an unplanned outage through that time.  We also have a contract in place for the purchase of replacement power during the scheduled Vermont Yankee plant outage in late 2008.

In the second quarter of 2008, we entered into several forward energy sales for 2009, locking in the price for approximately 29 percent of our forecasted excess energy available for resale for the year.  In July 2008 we sold an additional 7 percent of such energy.  As discussed above, these transactions help to stabilize future resale revenue by reducing price volatility.  We continue to work with counterparties in New England to sell forward more of our forecasted excess in 2009 and beyond.  Our current credit rating limits the number of counterparties we currently deal with, requires that we limit the net sale position with counterparties, and that we structure transactions to limit collateral exposures.

During July 2008 the Vermont Yankee plant reduced production levels (also referred to as a derate) for 11 days, reaching a low of approximately 20 to 30 percent capacity during some of that time.  The derate resulted from issues related to the plant's cooling towers.  The estimated incremental costs of the replacement power that we purchased during the derate amounted to approximately $1.1 million.  Our purchases of Vermont Yankee output normally contribute to the excess power position, therefore we have also estimated the loss of approximately $1.2 million in resale sales revenue during the derate.  We will record the total impact of the derate, estimated at $2.3 million, in the third quarter of 2008.

Future Power Supply: Our contract for power purchases from VYNPC ends in 2012, but there is a risk that the plant could be shut down earlier than expected if ENVY determines that it is not economical to continue operating the plant.  Hydro-Quebec contract deliveries end in 2016, but the average level of deliveries decreases by approximately 20 percent to 30 percent after 2012, and by approximately 85 percent after 2015.  There is a risk that future sources available to replace these contracts may not be as reliable and the price of such replacement power could be significantly higher than what we have in place today.  These contracts are described in Note 9 - Commitments and Contingencies.

ENVY has submitted a renewal application with the Nuclear Regulatory Commission ("NRC") for a 20-year extension of the Vermont Yankee plant operating license.  ENVY also needs approval from the PSB and Vermont Legislature to continue to operate beyond 2012.  At this time, ENVY has not received approvals for the license extension, but we are continuing to participate in negotiations for a power contract beyond 2012 and cannot predict the outcome at this time.

An early shutdown of the Vermont Yankee plant would cause us to lose the economic benefit of an energy volume equal to close to 50 percent of our total committed supply and we would have to acquire replacement power resources for approximately 40 percent of our estimated power supply needs.  Based on projected market prices as of June 30, 2008, the incremental replacement cost of lost power, including capacity, is estimated to average $84 million annually.  This estimate is based on projected market prices at a point in time and therefore can change significantly depending on market price volatility.  We are not able to predict whether there will be an early shutdown of the Vermont Yankee plant or whether the PSB would allow timely and full recovery of increased costs related to any such shutdown.  However, an early shutdown could materially impact our financial position and future results of operations if the costs are not recovered in retail rates in a timely fashion.

We, other Vermont electric utilities and HQ-Production are using a steering committee structure to develop background materials, terms and supporting actions needed in negotiations for future power purchases from Hydro-Quebec.  We believe there is a high probability that we will have a new contract with Hydro-Quebec, and we have agreed to target completion of proposed draft terms by the end of 2008, with a proposed contract for review by the PSB in 2009.  We cannot predict whether a contract will ultimately be approved or, if approved, the quantities of power to be purchased or the price terms of any purchases.

Page 29 of 33

RECENT ENERGY POLICY INITIATIVES

Several laws have been passed since 2005 that impact electric utilities in Vermont.  The major provisions of the new laws that could affect our business are described in our 2007 Annual Report on Form 10-K.  Since that report, the Vermont Legislature passed two bills related to operations at Vermont Yankee.  S. 269, the "Comprehensive Vertical Audit and Reliability Assessment of Vermont Yankee Nuclear Power Plant," signed by the governor, establishes protocols for state review of the plant.  A separate bill, S. 373, which addresses the funding mechanism for the plant’s future decommissioning costs, passed the legislature but was vetoed by the governor.  The Legislature adjourned in May 2008 so the governor’s veto constitutes final action on S.373. 

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

For the six months ended June 30, 2008, there were no material changes from the disclosures in our Annual Report on Form 10-K for the year ended December 31, 2007 except for our derivative financial instruments, which include certain power contracts and financial transmission rights.  Summary information related to the fair value of these derivatives is shown in the table below (dollars in thousands).

	Forward			Forward
	Sales			Purchase			Hydro-Quebec
	Contracts			Contracts			Sellback #3			Total
Total fair value at December 31, 2007 - unrealized loss	$	(2,037	)	$	(481	)	$	(4,592	)	$	(7,110	)
Plus new contracts entered into during the period		(1,270	)		33			0			(1,237	)
Less amounts settled during the period		4,167			(33	)		0			4,134
Change in fair value during the period		(9,649	)		3,771			(3,814	)		(9,692	)
Total fair value at June 30, 2008 - unrealized (loss) gain, net	$	(8,789	)	$	3,290		$	(8,406	)	$	(13,905	)
Estimated fair value at June 30, 2008 for changes in projected market price:
10 percent increase	$	(12,027	)	$	4,204		$	(13,448	)	$	(21,271	)
10 percent decrease	$	(5,545	)	$	2,376		$	(3,363	)	$	(6,532	)

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures As of the quarter ended June 30, 2008, our management, with participation from the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934).  Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting  There were no changes in our internal control over financial reporting during the quarter ended June 30, 2008 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

Page 30 of 33

PART II - OTHER INFORMATION
Item 1.	Legal Proceedings. The Company is involved in legal and administrative proceedings in the normal course of business and does not believe that the ultimate outcome of these proceedings will have a material adverse effect on its financial position or results of operations.
Item 1A.	Risk Factors. In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I "Item 1A. Risk Factors", in our Annual Report on Form 10-K for the year ended December 31, 2007, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing our Company.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.
Item 4.	Submission of Matters to a Vote of Security Holders.
	(a)	The registrant held its Annual Meeting of Stockholders on May 6, 2008.
	(b)	Directors elected whose terms will expire in year 2011.
				Votes FOR	Votes WITHHELD
		Douglas J. Wacek		8,370,825	319,809
		Robert H. Young		8,359,646	330,989
		Other Directors whose terms will expire in year 2010.
		Bruce M. Lisman Janice L. Scites William J. Stenger
		Other Directors whose terms will expire in year 2009.
		Robert L. Barnett Robert G. Clarke Mary Alice McKenzie William R. Sayre
	(c)	Approval of Amended 2002 Long-Term Incentive Plan.
		For Against Abstain Broker Non-vote	5,795,889 494,168 1,026,575 1,374,002
	(d)	Ratification of the appointment of Deloitte & Touche LLP as independent registered public accountants for fiscal year ending December 31, 2008.
		For Against Abstain	8,548,711 72,054 69,867
	(e)	Stockholder proposal requesting the Board of Directors take steps to declassify.
		For Against Abstain Broker Non-vote	5,706,222 566,405 719,904 1,698,103

Page 31 of 33

Item 5.		Other Information. On August 4, 2008 the Board of Directors adopted changes to the existing Officers' Supplemental Retirement and Deferred Compensation Plan ("SERP") and the Deferred Compensation Plan for Officers and Directors of Central Vermont Public Service Corporation ("Deferred Compensation Plan") to comply with the new statutory rules under Section 409A of the Internal Revenue Code of 1986, as amended, and to preserve the flexibility of "grandfathered" participants enjoyed pre-409A (also known as bifurcating the plans). Section 409A alters the income tax treatment of compensation that is regarded as deferred under a nonqualified deferred compensation plans and arrangements.  Section 409A also imposes other requirements on such plans and arrangements. ·409A Compliance for the SERP Plan includes: oDecoupling SERP payment elections from basic pension plan payment elections oBifurcating plan to create flexibility for "grandfathered" participants oNew benefit election form created for all participants to elect time and method of payment o"Grandfathered" participants that believe they will take their benefit in a lump-sum must complete a form for their "grandfathered" benefit as well ·409A Compliance for the Deferred Compensation Plan includes: oBifurcating plan to create flexibility for "grandfathered" participants oFor "grandfathered" participants, separately account for the pre-409A funds (pre-2005 deferrals) as well as all earnings thereon oFor "grandfathered" participants, complete new election form for pre-409A funds to designate time and method of payment
Item 6.		Exhibits.
	(a)			List of Exhibits
			4.1		Forty-Sixth Supplemental Indenture, dated as of May 1, 2008, from the Company to U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.7 to the Company’s Form 8-K filed with the SEC on May 15, 2008).
			4.2		Bond Purchase Agreement, dated as of May 15, 2008, among the Company and the purchasers listed on Schedule A thereto (incorporated by reference to Exhibit 4.8 to the Company’s Form 8-K filed with the SEC on May 15, 2008).
			A 10.3.1		Officers' Supplemental Retirement and Deferred Compensation Plan, Amended and Restated August 4, 2008, With An Effective Date of January 1, 2008.
			A 10.7.1		Deferred Compensation Plan for Officers and Directors of Central Vermont Public Service Corporation Amended and Restated August 4, 2008, With An Effective Date of January 1, 2005.
				31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
				31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
				32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
				32.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Page 32 of 33

SIGNATURE

      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/ Pamela J. Keefe
	Pamela J. Keefe Vice President, Chief Financial Officer, and Treasurer

Dated  August 8, 2008

Page 33 of 33