10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended     June 30, 2007    

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)

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

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

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

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

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

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.

Large accelerated filer [   ]         Accelerated filer [X]         Non-accelerated filer [   ]

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the 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, 2007 there were outstanding 10,194,531 shares of Common Stock, $6 Par Value.

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Form 10-Q - 2007

Table of Contents

		Page
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Statements of Income (unaudited) for the three and six    months ended June 30, 2007 and 2006	1
	Condensed Consolidated Statements of Comprehensive Income (unaudited) for the    three and six months ended June 30, 2007 and 2006	2
	Condensed Consolidated Statements of Cash Flows (unaudited) for the    six months ended June 30, 2007 and 2006	3
	Condensed Consolidated Balance Sheets as of June 30, 2007 (unaudited) and    December 31, 2006	4
	Condensed Consolidated Statement of Changes in Common Equity (unaudited) for the    six months ended June 30, 2007	6
	Notes to Condensed Consolidated Financial Statements	7
Item 2.	Management's Discussion and Analysis of Financial Condition and    Results of Operations	18
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	27
Item 4.	Controls and Procedures	27
PART II	OTHER INFORMATION	28
SIGNATURES		29
EXHIBIT INDEX		30

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (in thousands, except per share data) (unaudited)
	Three months ended June 30,		Six months ended June 30,
	2007	2006	2007	2006
Operating Revenues	$77,380	$78,992	$164,076	$161,247
Operating Expenses Purchased Power - affiliates Purchased Power - other Production Transmission - affiliates Transmission - other Other operation Maintenance Depreciation and amortization Taxes other than income Income tax (benefit) expense Total Operating Expenses	11,817  28,002  2,806  1,416  3,805  13,219  8,471  3,775  3,776      (594)  76,493	21,050  21,933  2,339  1,501  3,500  13,095  5,331  4,129  3,628       248  76,754	27,955  54,124  5,945  2,913  7,992  27,007  13,928  7,514  7,504      2,244  157,126	37,860  47,611  5,192  2,844  6,952  25,658  10,846  8,220  7,244      1,962  154,389
Operating Income	887	2,238	6,950	6,858
Other Income Equity in earnings of affiliates Allowance for equity funds during construction Other income Other deductions Provision for income taxes Total Other Income	1,589  (1) 1,049  (427)     (364)   1,846	352  40  1,295  (743)     (144)      800	3,291  16  2,116  (1,020)     (890)    3,513	869  63  3,448  (1,464)       (597)     2,319
Interest Expense Interest on long-term debt Other interest Allowance for borrowed funds during construction Total Interest Expense	1,799  414         (1)   2,212	1,799  257        (13)    2,043	3,598  644          (6)   4,236	3,598  508          (21)     4,085
Net Income Dividends declared on preferred stock Earnings available for common stock	521          92      $429	995         92     $903	6,227       184  $6,043	5,092        184   $4,908
Per Common Share Data: Basic earnings per share Diluted earnings per share	$0.04  $0.04	$0.08  $0.08	$0.59  $0.58	$0.43  $0.43
Average shares of common stock outstanding - basic Average shares of common stock outstanding - diluted Dividends declared per share of common stock	10,186,907  10,307,095  $0.23	10,634,854  10,682,809  $0.46	10,161,336  10,355,990  $0.69	11,403,213  11,460,706  $0.46

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

Page 1 of 30

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (in thousands) (unaudited)
	Three months ended June 30,		Six months ended June 30,
	2007	2006	2007	2006
Net Income	$521	$995	$6,227	$5,092
Other comprehensive income, net of tax: Items included in employee defined benefit plans:    Amortization of actuarial losses net of income taxes      of $3, $0, $6 and $0    Amortization of prior service cost net of income taxes      of $3, $0, $5 and $0 Investments:    Unrealized holding gain net of income taxes of $0, $4, $0 and $26    Less reclassification adjustment for gains included in net income,      net of income taxes of $0, $(7), $0 and $(24) Comprehensive income adjustments	4  4  - -          -         8	- -  - -  5    (12)     (7)	9  7  - -           -        16	- -  - -  38       (37)          1
Total comprehensive income	$529	$988	$6,243	$5,093

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW (in thousands) (unaudited)
	Six months ended June 30,
	2007	2006
Cash flows provided by (used for): OPERATING ACTIVITIES Net income Adjustments to reconcile net income to net cash provided by operating activities: Equity in earnings of affiliates Distributions received from affiliates Depreciation and amortization Deferred income taxes and investment tax credits Non-cash employee benefit plan costs Regulatory and other amortization, net Gain on sales of property Other non-cash expense, net Changes in assets and liabilities: Decrease in accounts receivable and unbilled revenues Decrease in accounts payable Decrease (increase) in other current assets (Increase) decrease in special deposits and restricted cash for power collateral Employee benefit plan funding Increase (decrease) in other current liabilities Other non-current assets and liabilities and other Net cash provided by operating activities	$6,227  (3,291) 2,510  7,514  (55) 3,604  (2,247) - -  1,644  5,764  (3,411) 1,265  (1,654) (7,879) (1,327)       (16)   8,648	$5,092  (869) 880  8,220  141  5,220  (723) (300) 526  5,060  (1,231) (833) 7,419  (17,582) 1,040        670   12,730
INVESTING ACTIVITIES Construction and plant expenditures Investments in available-for-sale securities Proceeds from sale of available-for-sale securities Utility investments Proceeds from sale of property Return of capital from investments in affiliates Other investments Net cash (used for) provided by investing activities	(9,772) (816) 734  - -  342  108       (270)   (9,674)	(9,531) (245,406) 311,689  (8,886) 334  103      (465)  47,838
FINANCING ACTIVITIES Proceeds from issuance of common stock Common and preferred dividends paid Proceeds from borrowings under revolving credit facility Repayments under revolving credit facility Retirement of preferred stock subject to mandatory redemption Decrease in special deposits held for preferred stock redemptions Reduction in capital lease obligations Stock reacquisition and other Net cash provided by (used for) financing activities	974  (4,857) 19,600  (13,150) (1,000) 1,000  (436)        287      2,418	675  (5,496) 300  (300) (2,000) 2,000  (510) (51,123) (56,454)
Net increase in cash and cash equivalents Cash and cash equivalents at beginning of the period Cash and cash equivalents at end of the period	1,392      2,799    $4,191	4,114      6,576  $10,690
Supplemental Disclosure of Cash Flow Information: Cash paid for:   Interest (net of amounts capitalized)   Income taxes (net of refunds)	$4,008 $5,052	$3,908  $1,956

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands, except share data) (unaudited)
	June 30, 2007	December 31, 2006
ASSETS Utility plant Utility plant in service, at original cost Less accumulated depreciation Utility plant in service, at original cost, net of accumulated depreciation Property under capital leases Construction work-in-progress Nuclear fuel, net Total utility plant, net	$527,523   231,131 296,392 7,055 9,165       1,299   313,911	$517,816   226,018 291,798 7,485 8,496       1,017   308,796
Investments and other assets Investments in affiliates Non-utility property, less accumulated depreciation    ($3,698 in 2007 and $4,048 in 2006) Millstone decommissioning trust fund Other Total investments and other assets	39,913 1,664 5,827       7,429     54,833	39,339 1,640 5,476      7,120    53,575
Current assets Cash and cash equivalents Restricted cash Special deposits Accounts receivable, less allowance for uncollectible accounts    ($1,860 in 2007 and $1,707 in 2006) Accounts receivable - affiliates, less allowance for uncollectible accounts    ($48 in 2007 and $48 in 2006) Unbilled revenues Materials and supplies, at average cost Prepayments Deferred income taxes Assets held for sale Other current assets Total current assets	4,191 2,385 2,850 22,227 135 14,716 5,415 7,492 4,517 - -       1,414    65,342	2,799 3,081 1,500 27,042 73 16,654 5,298 7,389 2,899 386       1,446     68,567
Deferred charges and other assets Regulatory assets Other deferred charges - regulatory Other deferred charges and other assets Total deferred charges and other assets TOTAL ASSETS	50,513 11,491       5,541     67,545 $501,631	52,179 12,127       5,694     70,000 $500,938

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands, except share data) (unaudited)
	June 30, 2007	December 31, 2006
CAPITALIZATION AND LIABILITIES Capitalization Common stock, $6 par value, 19,000,000 shares authorized,    12,443,405 issued and 10,193,430 outstanding at June 30, 2007    and 12,382,801 issued and 10,132,826 outstanding at December 31, 2006 Other paid-in capital Accumulated other comprehensive loss Treasury stock, at cost (2,249,975 shares) Retained earnings Total common stock equity Preferred and preference stock not subject to mandatory redemption Preferred stock subject to mandatory redemption Long-term debt Capital lease obligations Total capitalization	$74,660  55,424  (528) (51,186) 101,703  180,073  8,054  2,000  115,950      6,180  312,257	$74,297  54,225  (544) (51,186)  102,560  179,352  8,054  3,000  115,950       6,612   312,968
Current liabilities Current portion of preferred stock subject to mandatory redemption Accounts payable Accounts payable - affiliates Notes payable Dividends declared Nuclear decommissioning costs Power contract derivatives Other current liabilities Total current liabilities	1,000  4,929  9,891  17,250  2,344  2,540  2,325    21,206    61,485	1,000  6,382  12,022  10,800  - -  2,737  1,554    20,336    54,831
Deferred credits and other liabilities Deferred income taxes Deferred investment tax credits Nuclear decommissioning costs Asset retirement obligations Accrued pension and benefit obligations Power contract derivatives Other deferred credits - regulatory Other deferred credits and other liabilities Total deferred credits and other liabilities Commitments and contingencies TOTAL CAPITALIZATION AND LIABILITIES	34,281  3,530  10,979  3,152  31,935  5,579  11,662    26,771   127,889  $501,631	32,467  3,720  12,166  3,041  37,547  6,443  12,687    25,068   133,139  $500,938

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

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CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN COMMON STOCK EQUITY (in thousands, except share data) (unaudited)
	Common Stock				Treasury Stock
	Shares Issued	Amount	Other Paid-in Capital	Accumulated Other Comprehensive Loss	Share	Amount	Retained Earnings	Total
Balance, December 31, 2006 Cumulative effect of adoption of    FIN 48 Adjusted balance at January 1, 2007 Net income Other comprehensive income Dividend reinvestment plan Stock options exercised Share-based compensation Dividends declared on common and    preferred stock Amortization of preferred stock    issuance expenses Loss on reacquisition of capital stock Balance, June 30, 2007	12,382,801                    12,382,801 9,721 47,475 3,408                    12,443,405	$74,297               $74,297 58 285 20               $74,660	$54,225                $54,225 286 631 270 9            3 $55,424	$(544)             $(544) 16              $(528)	2,249,975                 2,249,975                 2,249,975	$(51,186)                $(51,186)                $(51,186)	$102,560          120  $102,680  6,227  (7,201)           (3) $101,703	$179,352           120  $179,472  6,227  16  344  916  290  (7,201) 9               -  $180,073

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

These unaudited interim financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC"). 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 ("GAAP") have been condensed or omitted. In management's 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 the Company's annual report on Form 10-K for the year ended December 31, 2006.

Regulatory Accounting The Company's 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, the Company prepares its financial statements in accordance with SFAS No. 71, Accounting for the Effects of Certain Types of Regulation ("SFAS No. 71"). The application of SFAS No. 71 results in differences in the timing of recognition of certain expenses from those of other businesses and industries. In the event the Company determines that it no longer meets the criteria for applying SFAS No. 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 condit ions expected to impact future cost recovery, management believes future recovery of its regulatory assets is probable. Criteria that could give rise to the discontinuance of SFAS No. 71 include: 1) increasing competition that restricts a company's ability to establish prices to recover specific costs, and 2) a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. See Note 4 - Retail Rates and Regulatory Accounting for additional information.

Income Taxes In accordance with SFAS No. 109, Accounting for Income Taxes, the Company recognizes deferred tax assets and liabilities for the cumulative effect of all temporary differences between financial statement carrying amounts and the tax basis of existing assets and liabilities using the tax rate expected to be in effect when the differences are expected to reverse. Investment tax credits associated with utility plant are deferred and amortized ratably to income over the lives of the related properties. The Company records a valuation allowance for deferred tax assets if management determines that it is more likely than not that such tax assets will not be realized.

In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109 ("FIN 48"). FIN 48 clarifies the methodology to be used in estimating and reporting amounts associated with uncertain tax positions, including interest and penalties. The Company adopted FIN 48 on January 1, 2007 as required. Upon adoption and in accordance with FIN 48, the Company recognized the cumulative effect of approximately $0.1 million as an increase in beginning retained earnings related to a decrease in the liability for unrecognized income tax benefits. At the adoption date and at June 30, 2007, the Company had $0.7 million of unrecognized tax benefits, which would affect the effective tax rate if recognized. In the second quarter of 2007, management determined that it would file amended returns and recorded an additional $1.4 million FIN 48 liability, which is included in Other Deferred Credits and Liabilities on the Condensed Consolidated Ba lance Sheet.  Because of the impact of deferred tax accounting the disallowance of this item would not affect the effective tax rate.

The Company recognizes interest related to unrecognized tax benefits as interest expense and penalties as other deductions. Accrued interest related to uncertain tax positions amounted to less than $0.1 million as of June 30, 2007. The tax years 2003 through 2006 remain open to examination by major taxing jurisdictions to which the Company is subject. The Internal Revenue Service is currently auditing the 2004 tax year.

Derivative Financial Instruments The Company accounts for certain power contracts as derivatives under the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted and SFAS No. 149, Amendment of Statement 133 Derivative Instruments and Hedging Activities, (collectively "SFAS No. 133"). These statements require that derivatives be recorded on the balance sheet at fair value. At December 31, 2006, the Company's power contracts that are derivatives included: 1) one long-term purchased power contract that allows the seller to repurchase specified amounts of power with advance notice (Hydro-Quebec Sellback #3); 2) one long-term forward sale contract; and 3) one short-term forward purchase contract. During the first six months of 2007, the short-term forward purchase contract

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ended, and the Company entered into four additional power contract derivatives including three short-term forward sale contracts and one forward purchase contract for purchases during the scheduled Vermont Yankee plant outage in 2008. The Company enters into forward sale contracts to reduce price volatility, since its long-term power forecasts show energy purchases and production in excess of load requirements.

The estimated fair values of power contract derivatives are based on over-the-counter quotations or broker quotes at the end of the reporting period, with the exception of Hydro-Quebec Sellback #3, which is valued using a binomial tree model and quoted market data when available, along with appropriate valuation methodologies. At June 30, 2007, the estimated fair value of three of the six power contract derivatives was an unrealized loss of $7.9 million and the estimated fair value of the remaining three was an unrealized gain of $0.5 million. At December 31, 2006, the estimated fair value of all power contract derivatives was an unrealized loss of $8.0 million.

Based on a PSB-approved Accounting Order, the Company records the change in fair value of power contract derivatives 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.

Reclassifications Certain prior year amounts have been reclassified to conform to the current year presentation. The Company has reclassified $0.7 million from Transmission - other in the second quarter of 2006 to Transmission - affiliates.

Recent Accounting Pronouncements

FIN 48: See Income Taxes above.

SFAS No. 157:  In September 2006, the FASB issued Statement No. 157, Fair Value Measurements ("SFAS No. 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 GAAP. As a result of SFAS No. 157, there is now a common definition of fair value to be used throughout GAAP. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 (beginning January 1, 2008 for the Company). The Company is currently evaluating the impact that SFAS No. 157 will have on its financial position, results of operations and cash flows.

SFAS No. 158: The Company 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 No. 158") as of December 31, 2006. SFAS No. 158 also requires companies to measure plan assets and benefit obligations as of the same date as their fiscal year-end balance sheet date. This provision of SFAS No. 158 is effective for the Company in 2008. The Company estimates that changing its annual benefit measurement date from September 30 to December 31 will result in a pre-tax charge to retained earnings of $1.7 million. The Company is in the process of seeking rate recovery for the regulated utility portion of the impact resulting from the change. If rate recovery is permitted, a regulatory asset would be recorded for $1.5 million, if not; the total after-tax charge to retained earnings would be approximately $1.0 million. The Company cannot predic t the outcome of this matter at this time.

SFAS No. 159:  In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities ("SFAS No. 159"). SFAS No. 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. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007 (beginning January 1, 2008 for the Company). The Company has not yet evaluated what impact, if any, the adoption of SFAS No. 159 will have on its financial position, results of operations and cash flows.

EITF 06-04 and EITF 06-10: In September 2006, the FASB issued EITF Issue 06-04, Accounting for Deferred Compensation and Postretirement Benefit Aspects of Endorsement Split Dollar Life Insurance Arrangements, ("EITF 06-04"). EITF 06-04 requires employers to record a liability for future benefits for endorsement split-dollar life insurance arrangements that provide a postretirement benefit to an employee. In March 2007, the FASB issued EITF 06-10, Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements ("EITF 06-10"). EITF 06-10 describes whether an entity should record a liability for the postretirement benefit associated with a collateral assignment split-dollar life insurance arrangement and how an employer should recognize and measure the related asset. Both EITFs become effective for fiscal periods beginning after December 15, 2007 (beginning January 1, 2008 for the Company). The Company is currently evaluating the impact, if any, these EITFs will have on its financial position, results of operations and cash flows.

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NOTE 2 - EARNINGS PER SHARE ("EPS")

The Condensed Consolidated Statements of Income include basic and diluted per share information. A reconciliation of the numerator and denominator used in calculating basic and diluted EPS follows (in thousands, except share information):

	Three Months Ended June 30,		Six Months Ended June 30,
	2007	2006	2007	2006
Numerator for basic and diluted EPS: Net income Dividends declared on preferred stock Earnings available for common stock Denominators for basic and diluted EPS: Weighted-average basic shares of common stock outstanding    Dilutive effect of stock options    Dilutive effect of performance shares Weighted-average diluted shares of common stock outstanding	$521    (92) $429  10,186,907  104,636         15,552  10,307,095	$995       (92) $903  10,634,854  42,473           5,482  10,682,809	$6,227     (184) $6,043  10,161,336  182,437       12,217  10,355,990	$5,092      (184) $4,908  11,403,213  51,970            5,523   11,460,706

All outstanding stock options were included in the computation of diluted shares for the second quarter and first six months of 2007 because the exercise prices were lower than the average market price of the common shares. Outstanding stock options totaling 259,417 in the second quarter and 198,017 in the first six months of 2006 were excluded from the computation of diluted shares because the exercise prices were above the average market price of the common shares.

NOTE 3 - INVESTMENTS IN AFFILIATES

Vermont Electric Power Company, Inc. ("VELCO") and Vermont Transco LLC ("Transco") In June 2006, VELCO's Board of Directors, the PSB and the FERC approved a plan to transfer substantially all of VELCO's business operations to Transco, a Vermont limited liability company. On June 30, 2006, VELCO's assets were transferred to Transco in exchange for 2.4 million Class A Membership Units, and Transco assumed all of VELCO's debt. VELCO and its employees manage Transco's operations under a Management Services Agreement between VELCO and Transco. Transco operates under an Operating Agreement among VELCO, Transco, the Company, Green Mountain Power and most of the other Vermont electric utilities. Transco also operates under the Amended and Restated Three Party Agreements, assigned to Transco from VELCO, among the Company, Green Mountain Power, VELCO and Transco. In 2006, the Company invested a total of $23.3 million in Transco, which is represented by Class A Membership Units in Transco that earn an a llowed rate of return of 11.5 percent. At June 30, 2007, the Company's total direct and indirect interest in Transco was 44.34 percent.

Summarized financial information for Transco follows (in thousands). These amounts are also included in VELCO's consolidated financial information below.

	Three Months Ended June 30,	Six Months Ended June 30,
	2007	2007
Operating revenues Operating income Net income Company's ownership interest Company's equity in net income	$12,221  $5,747  $3,393  29.86% $1,082	$24,885  $11,287  $6,900  29.86% $2,243

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

	Three Months Ended June 30,		Six Months Ended June 30,
	2007	2006	2007	2006
Operating revenues Operating income Net income before non-controlling interest Less members non-controlling interest in net income Net income Company's common stock ownership interest Company's equity in net income	$12,310  $5,404  $3,087    2,360     $727  47.05% $386	$8,469  $2,365  $731        -  $731  47.05% $352	$25,097  $10,492  $6,261    4,725  $1,536  47.05% $783	$17,456  $4,579  $1,502            -  $1,502  47.05% $743

Transmission services provided by Transco are billed to the Company under the 1991 Transmission Agreement also referred to as the Vermont Transmission Agreement ("VTA"). The Company and 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 requests by Transco for revisions to the VTA. Hearings on these proceedings are scheduled to begin in January 2008. Additionally, the parties to these proceedings, including the Company, have and continue to participate in settlement negotiations. The Company is not able to predict the outcome of this matter at this time.

Transco (previously VELCO) provided transmission services to the Company amounting to $1.4 million for the second quarter and $2.9 million for the first six months of 2007 and $1.5 million in the second quarter and $2.8 million in the first six months of 2006. These amounts are reflected as Transmission - affiliates on the Condensed Consolidated Statements of Income.

Vermont Yankee Nuclear Power Corporation ("VYNPC") Summarized financial information for VYNPC follows (in thousands):

	Three Months Ended June 30,		Six Months Ended June 30,
	2007	2006	2007	2006
Operating revenues Operating income Net income Company's common stock ownership interest Company's equity in net income	$31,920  $1,005  $193  58.85% $113	$56,013  $993  $168  58.85% $99	$76,292  $1,832  $418  58.85% $246	$100,360  $1,769  $341  58.85% $201

Purchased power - affiliates on the Company's Condensed Consolidated Statements of Income includes sales from VYNPC of approximately $11.1 million for the second quarter and $26.6 million for the first six months of 2007 and $19.6 million in the second quarter and $35.1 million in the first six months of 2006. Also see Note 7 - Commitments and Contingencies.

Maine Yankee, Connecticut Yankee and Yankee Atomic All three companies collect decommissioning and closure costs through FERC-approved wholesale rates charged under power agreements among several New England utilities, including the Company. Historically, the Company's share of these costs has been recovered from retail customers through PSB-approved rates. The Company believes its share of decommissioning and closure costs for each plant will continue to be recovered through the regulatory process. There is a risk that if FERC disallows future cost recovery for any of the three companies, the PSB would also disallow recovery of the Company's share in its retail rates.

The Company's share of Maine Yankee, Connecticut Yankee and Yankee Atomic 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, 2007, the Company had regulatory assets of $2.8 million related to Maine Yankee, $7.6 million related to Connecticut Yankee and $3.2 million related to

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Yankee Atomic (including $0.1 million for incremental decommissioning costs already paid by the Company). These estimated costs are being collected from customers through existing retail rate tariffs. Total billings from the three companies amounted to $0.7 million for the second quarter and $1.4 million for the first six months of 2007 and $1.5 million in the second quarter and $2.9 million in the first six months of 2006. These amounts are included in Purchased power - affiliates on the Company's Condensed Consolidated Statements of Income.

Maine Yankee: Plant decommissioning activities were completed in 2005 and the Nuclear Regulatory Commission ("NRC") amended Maine Yankee's operating license in October 2005 for operation of the Independent Spent Fuel Storage Installation. Maine Yankee's wholesale rates are currently based on a September 2004 FERC-approved settlement.

Connecticut Yankee: Final site-work is projected to be completed in 2007 followed by NRC approval to begin the Independent Spent Fuel Storage Installation-only operations. Connecticut Yankee's wholesale rates are currently based on a November 16, 2006 FERC-approved settlement.

Yankee Atomic: Final site-work is projected to be completed in 2007 followed by NRC approval to begin the Independent Spent Fuel Storage Installation-only operations. Yankee Atomic's wholesale rates are currently based on a July 31, 2006 FERC-approved settlement.

Department of Energy ("DOE") Litigation: 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 DOE was to begin removing spent nuclear fuel 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 wholesale utility customers, including the Company, under FERC-approved contract rates, and these payments were collected from the Company's retail customers.

On September 30, 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. The three companies had claimed actual damages through the same periods in the amounts of $78.1 million for Maine Yankee, $37.7 million for Connecticut Yankee and $60.8 million for Yankee Atomic. On December 4, 2006, the DOE filed a notice of appeal to the United States Court of Appeals for the Federal Circuit ("Appeals Court") in all three cases, and on December 14, 2006, all three companies filed notices of cross appeals.

On February 9, 2007, the Appeals Court issued an order consolidating the three cases. On March 15, 2007, the Appeals Court issued an order making another case a companion appeal to the case, which will result in both appeals being heard consecutively. Due to the complexity of the issues and the appeals, the three companies cannot predict the amount of damages that will actually be received or the timing of the final determination of such damages. Each of the companies' respective FERC settlements require that damage payments, net of taxes and net of further spent fuel trust funding, be credited to ratepayers including the Company. The Company expects that its share of these payments, if any, would be credited to its ratepayers as well.

The Court's decision, if upheld, establishes the DOE's responsibility for reimbursing Maine Yankee for its actual costs through 2002 and Connecticut Yankee and Yankee Atomic for their actual costs through 2001 related to the incremental spent fuel storage, security, construction and other costs of the spent fuel storage installation. Although the decision leaves open the question regarding damages in subsequent years, the decision does support future claims for the remaining spent fuel storage installation construction costs. The Company cannot predict the ultimate outcome of this decision on appeal.

NOTE 4 - RETAIL RATES AND REGULATORY ACCOUNTING

Retail Rates On December 7, 2006, the PSB issued an Order ("2006 Rate Order") approving a 4.07 percent rate increase effective January 1, 2007. The 2006 Rate Order provided, among other things, an allowed rate of return on common equity of 10.75 percent capped until the Company's next rate proceeding.

On January 12, 2007, the PSB issued an Order denying the Company's Accounting Order request for recovery of $1.5 million of incremental replacement power costs associated with a 2005 Vermont Yankee refueling outage. Pursuant to the 2006 Rate Order, because the 4.07 percent rate increase included recovery of the incremental replacement power costs, the Company is

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deferring (beginning January 1, 2007) $1.5 million of revenue over two years. The Company will continue such deferral until its next rate proceeding, at which time the total amount deferred will be returned to customers. As of June 30, 2007, deferrals amounted to $0.4 million and are included in Other deferred credits and other liabilities on the Condensed Consolidated Balance Sheet, with an offsetting reduction in Operating revenue on the Condensed Consolidated Statement of Income.

On May 15, 2007, the Company filed a request for a 4.46 percent rate increase (additional revenue of about $12.4 million on an annual basis), to be effective February 1, 2008.  The case is proceeding pursuant to an agreed-upon schedule, and a decision is expected in late January 2008.  The Company cannot predict the outcome of this rate proceeding at this time.

Regulatory Accounting Under SFAS No. 71, the Company accounts for certain transactions in accordance with permitted regulatory treatment such that 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 the Company no longer meets the criteria under SFAS No. 71 and there is not a rate mechanism to recover these costs, the Company would be required to write off $20.1 million of regulatory assets (total regulatory assets of $50.5 million less pension and postretirement medical costs of $30.4 million), $11.5 million of other deferred charges - regulatory and $11.7 million of other deferred credits - regulatory. This would result in a total extraordinary charge to operations of $19.9 million pre-tax as of June 30, 2007. The Company would also be required to record pension and postretirement benefit costs of $30.4 million on a pre-tax basis to Accumulated Other C omprehensive Loss as a reduction in stockholder's equity, and would be required to determine any potential impairment to the carrying costs of deregulated plant. The primary components of Regulatory assets, Other deferred charges - regulatory and Other deferred credits - regulatory are shown in the table that follows (in thousands).

	June 30, 2007	December 31, 2006
Regulatory assets:* Pension and postretirement medical costs - SFAS No. 158 Nuclear plant dismantling costs Income taxes Nuclear plant refueling outage costs - Millstone Unit #3 Asset retirement obligations Other Total regulatory assets	$30,395  13,602  3,862  1,362  548         744  $50,513	$31,705  15,033  3,810  307  501      823  $52,179
Other deferred charges - regulatory: Vermont Yankee sale costs (tax) Unrealized loss on power contract derivatives Tree trimming, pole treating and other Total other deferred charges - regulatory	$3,130  7,904         457  $11,491	$3,130  7,997      1,000  $12,127
Other deferred credits - regulatory: Vermont utility overearnings 2001 - 2003 Asset retirement obligation - Millstone Unit #3 Environmental remediation Vermont Yankee IRS settlement Emission allowances and renewable energy credits Unrealized gain on power contract derivatives Other Total other deferred credits - regulatory	$2,882  3,337  1,759  907  770  547      1,460  $11,662	$4,803  3,055  1,648  1,088  924  - -      1,169  $12,687
*Regulatory assets are being recovered in retail rates, except for asset retirement obligations. The regulatory   assets included in Other and small portions of nuclear plant dismantling costs are earning a return.

NOTE 5 - NOTES PAYABLE

The Company has a three-year $25.0 million unsecured revolving credit facility with a lending institution pursuant to a Credit Agreement dated October 21, 2005. 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.

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At June 30, 2007, the Company had $6.5 million of borrowings outstanding under the facility, included in Notes Payable on the Condensed Consolidated Balance Sheet, and $6.0 million of letters of credit. At December 31, 2006 the only amounts outstanding under this facility were $4.5 million of letters of credit, which were cancelled in the first quarter of 2007.

NOTE 6 - PENSION AND POSTRETIREMENT MEDICAL BENEFITS

Components of net periodic benefit costs are as follows:

Pension Benefits	Three Months Ended June 30,		Six Months Ended June 30,
	2007	2006	2007	2006
Net benefit costs include the following components Service cost Interest cost Expected return on plan assets Amortization of net actuarial loss Amortization of prior service cost Net periodic benefit cost Less amounts capitalized Net benefit costs expensed	$888  1,561  (1,680) 146       100  1,015       181     $834	$922  1,493  (1,436) 196       100  1,275       202  $1,073	$1,776  3,122  (3,360) 292       200  2,030       352  $1,678	$1,844  2,986  (2,872) 392       200  2,550       406  $2,144

Postretirement Benefits	Three Months Ended June 30,		Six Months Ended June 30,
	2007	2006	2007	2006
Net benefit costs include the following components Service cost Interest cost Expected return on plan assets Amortization of net actuarial loss Amortization of transition obligation Net periodic benefit cost Less amounts capitalized Net benefit costs expensed	$145  377  (233) 263       64  616     110   $506	$177  424  (179) 398       64  884     140   $744	$290  754  (466) 526       128  1,232       214  $1,018	$354  848  (358) 796        128  1,768        282  $1,486

Pension and Postretirement Medical Benefit Trust Fund Contributions In June 2007, the Company contributed $4.1 million to its pension trust fund and $2.5 million to its postretirement medical trust funds. The Company does not plan to make any additional contributions to these trust funds in 2007. During 2006, the Company contributed $12.2 million in March and $8.6 million in September to its pension trust fund, and $4.1 million in March, $0.9 million in September and $0.2 million in December to its postretirement medical trust funds.

NOTE 7 - COMMITMENTS AND CONTINGENCIES

Millstone Unit #3 The Company has a 1.73 joint-ownership percentage in Millstone Unit # 3. As a joint owner, in which Dominion Nuclear Corporation ("DNC") is the lead owner with about 93.47 percent of the plant joint-ownership, the Company is responsible for its share of nuclear decommissioning costs. The Company has external trust funds dedicated to funding its joint-ownership share of future decommissioning costs. The Company has suspended contributions to the trust funds based on DNC's determination that the minimum NRC funding requirements are being met or exceeded. If a need for additional decommissioning funding is necessary, the Company will be obligated to resume contributions.

In January 2004, DNC filed, on behalf of itself and the two minority owners, including the Company, a lawsuit against the DOE seeking recovery of costs related to storage of spent nuclear fuel arising from the failure of the DOE to comply with its obligations to commence accepting such fuel in 1998. A trial is expected to be held in August 2008. The Company continues to pay its share of the DOE Spent Fuel assessment expenses levied on actual generation and will share in recovery from the lawsuit, if any, in proportion to its ownership interest.

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During Millstone Unit #3's scheduled refueling outage that began on April 7, 2007, DNC announced that it had discovered indications of cracking in the first stage of the high-pressure turbine. The plant began producing power for the grid on May 19, 2007. DNC is continuing to evaluate options ranging from replacing the turbine to continued use in its current condition. The Company cannot predict the outcome of this matter at this time.

Vermont Yankee The Company purchases its entitlement share of plant output through a Power Purchase Agreement ("PPA") between Entergy Nuclear Vermont Yankee, LLC ("ENVY") and VYNPC. ENVY has no obligation to supply energy to VYNPC over the amount the plant is producing, so entitlement holders receive reduced amounts when the plant is operating at a reduced level, and no energy when the plant is not operating. The Company purchased replacement power adequate to meet most of its hourly load obligations during the plant's scheduled refueling outage that started on May 13 and ended on June 6, 2007.

In 2006, the Company purchased forced outage insurance to cover additional costs, if any, of obtaining replacement power from other sources if the Vermont Yankee plant experiences unplanned outages between January 1 and December 31, 2007. The coverage applies to unplanned outages of up to 30 consecutive calendar days per outage event, and provides for payment to the Company of the difference between the spot market price and $40/mWh. The total maximum coverage is $10.0 million, with a $1.0 million total deductible. There were no claims under this contract in the first six months of 2007.

The PSB has not yet approved a March 16, 2006 settlement proposal reached by the Company, Green Mountain Power, ENVY and the Vermont Department of Public Service ("DPS") that resolves issues that were raised in a petition before the PSB regarding the Rate Payer Protection Proposal (outage protection related to the plant uprate). The Company's share of the settlement is estimated to be $1.6 million, but the settlement is not effective until the PSB issues a final order. Any amounts recovered by the Company will be returned to its customers. The Company cannot predict the timing or outcome of this matter at this time.

The Company is a party to a PSB Docket that was opened in June 2006 to investigate whether the reliability of the increased plant output will be adversely affected by the operation of the plant's steam dryer. On September 18, 2006, the PSB issued an order requiring ENVY to provide additional ratepayer protections that would protect Vermont utilities and ratepayers if the plant is forced to reduce output because of uprate-related steam dryer problems. The DPS and ENVY reached an agreement in a compliance filing with the PSB, which will provide protections in the event of a derate. The protections apply to incremental replacement power costs and would remain in effect for at least two months after the refueling outage during which the plant operates successfully with no steam dryer-related outages or derates. ENVY requested reconsideration of the PSB ruling. Reconsideration was denied and ENVY has appealed to the Vermont Supreme Court.

The PPA between ENVY and VYNPC contains a formula for determining the entitlement to power 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. The differing methods of calculation could have a material effect on the Company's power supply costs. The Company 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, the Company would have to acquire replacement power resources for approximately 40 percent of its estimated power supply needs. Based on the Company's projected market prices at June 30, 2007, the incremental replacement cost of lost power, including capacity, is estimated to average $55 million annually. The Company is not able to predict whether there will be an early shutdown of the Vermont Yankee plant or whether the PSB will allow timely and full recovery of increased costs related to any such shutdown. However, an early shutdown could materially impact the Company's financial position and future results of operations if the costs are not recovered in retail rates in a timely fashion.

Hydro-Quebec The Company purchases about 29 percent of its annual power supply energy (purchased and generated) from Hydro-Quebec under the Vermont Joint Owners ("VJO") Power Contract and related contracts negotiated between the Company 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 the Company's purchases related to the contract end in 2016.

In 1994, the Company negotiated a sellback arrangement whereby it 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 deliveries by 50 MW, including the use of a like amount of the Company's Phase I/II transmission

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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 load factor of 75 to 50 percent due to adverse hydraulic conditions as measured at certain agreed upon metering stations on regulated and unregulated rivers in Quebec. This second option can be exercised five times through October 2015. Hydro-Quebec has not yet exercised these options.

Based on elections made by the VJO in 2005 and 2006, purchases under the VJO Power Contract have been at an 80 percent load factor for the contract years beginning November 1, 2005 and 2006. After the contract year ending October 31, 2007, the annual load factor will be at 75 percent for the remainder of the contract, unless all parties to the contract agree to change it or there is a reduction due to the adverse hydraulic conditions described above. Total purchases under the VJO Contract amounted to $15.9 million for the second quarter and $32.7 million for the first six months of 2007, and $15.6 million in the second quarter and $31.8 million in the first six months of 2006.

Performance Assurance At June 30, 2007, the Company had posted $5.2 million of collateral under performance assurance requirements for certain of its power contracts as described below. In the second quarter of 2007, performance assurance requirements were met with cash deposits.

The Company is subject to performance assurance requirements for power purchase and sale transactions through ISO-New England under the Financial Assurance Policy for NEPOOL members. The Company's credit limit with ISO-New England is zero and it is required to post collateral for all net purchase transactions. At June 30, 2007, the Company had posted $2.3 million included in Restricted Cash on the Condensed Consolidated Balance Sheet.

The Company is currently selling power in the wholesale market pursuant to contracts with third parties, and is required to post collateral under certain conditions defined in the contracts. At June 30, 2007, the Company had posted $2.9 million included in Special Deposits on the Condensed Consolidated Balance Sheet.

The Company is subject to performance assurance for power purchase and sale transactions through ISO-New York. Activity in this market has been limited. At June 30, 2007, the Company had posted $0.1 million of collateral, which is included in Restricted Cash on the Condensed Consolidated Balance sheet.

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

Environmental Over the years, more than 100 companies have merged into or been acquired by the Company. 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 the Company 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. The Company believes that it is in compliance with all laws and regulations and has implemented procedures and controls to assess and assure compliance. Corrective action is taken when necessary. Below is a brief summary of known material sites included in the Company's environmental reserve.

Cleveland Avenue Property: The Cleveland Avenue property in Rutland, Vermont, was used by a predecessor to make gas from coal. Later, the Company sited various operations there. Due to the existence of coal tar deposits, polychlorinated biphenyl contamination and the potential for off-site migration, the Company 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, the Company updated its cost estimate of remediation for this site. The Company's liability for site remediation is expected to range from $2.3 million to $0.9 million. As of June 30, 2007, the Company has accrued $1.4 million representing the most likely cost of the remediation effort.

Brattleboro Manufactured Gas Facility: In the 1940s, the Company owned and operated a manufactured gas facility in Brattleboro, Vermont. The Company 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 the Company that its corrective action plan for the site was approved. That plan is now in place. In 2006, the Company updated the cost

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estimate of remediation for this site. The Company's liability for site remediation is expected to range from $1.3 million to $0.1 million. As of June 30, 2007, the Company has 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 ("PSNH") contacted the Company about this site. PSNH alleged that the Company was partially liable for cleanup, since the site was previously operated by Twin State Gas and Electric, which merged into the Company on the same day that PSNH bought the facility. In 2002, the Company reached a settlement with PSNH in which certain liabilities it might have had were assigned to PSNH in return for a cash settlement paid by the Company based on completion of PSNH's cleanup effort. The Company's remaining obligation is less than $0.1 million.

The reserve for environmental matters described above amounted to $2.0 million as of June 30, 2007 and $2.1 million as of December 31, 2006. The current and long-term portions are included as liabilities on the Condensed Consolidated Balance Sheets. The reserve represents management's best estimate of the cost to remedy issues at these sites based on available information as of the end of the reporting period. To the Company's 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 the Company for any other study or remediation.

The revised cost estimates for the Cleveland Avenue and Brattleboro sites resulted in a $3.2 million reduction in environmental reserves in the third quarter of 2006. At that time, the Company and DPS reached an agreement that a portion of the reduction in estimated remediation costs should be attributed to ratepayers, and that the Company should file an Accounting Order request with the PSB for approval of such treatment. The ratepayer portion, $1.6 million, is included in Other Deferred Credits - Regulatory on the Condensed Consolidated Balance Sheets. The PSB approved the Company's Accounting Order request in April 2007.

Catamount Indemnifications Under the terms of the agreements with Catamount and Diamond Castle, the Company agreed to indemnify them, and certain of their respective affiliates, in respect of a breach of certain representations and warranties and covenants, most of which expired on June 30, 2007, except certain items that customarily survive indefinitely. Indemnification is subject to a $1.5 million deductible and a $15.0 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 survive beyond June 30, 2007. The Company has not recorded any liability related to these indemnifications.

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.

NOTE 8 - SEGMENT REPORTING

The Company's primary operating segment is Central Vermont Public Service Corporation ("CV-VT"), which engages in the purchase, production, transmission, distribution and sale of electricity in Vermont. Unregulated Companies are below the quantitative thresholds individually and in the aggregate; therefore, prior year amounts in the table below have been revised to conform to current year presentation. Inter-segment revenues were nominal in all periods presented.

Three Months Ended	(in thousands)
June 30, 2007	CV-VT	Unregulated Companies	Reclassification & Consolidating Entries	Consolidated
Revenues from external customers Equity in earnings of affiliates Net income Total assets at June 30, 2007	$77,380  $1,589  $433  $499,957	$439  $-  $88  $1,962	$(439) $-  $-  $(288)	$77,380  $1,589  $521  $501,631
June 30, 2006
Revenues from external customers Equity in earnings of affiliates Net income Total assets at December 31, 2006	$78,992  $352  $846  $499,125	$469  $-  $149  $2,314	$(469) $-  $-  $(501)	$78,992 $352  $995  $500,938

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Six Months Ended	(in thousands)
June 30, 2007	CV-VT	Unregulated Companies	Reclassification & Consolidating Entries	Consolidated
Revenues from external customers Equity in earnings of affiliates Net income Total assets at June 30, 2007	$164,076  $3,291  $5,911  $499,957	$874  $-  $316  $1,962	$(874) $-  $-  $(288)	$164,076  $3,291  $6,227  $501,631
June 30, 2006
Revenues from external customers Equity in earnings of affiliates Net income Total assets at December 31, 2006	$161,247  $869  $4,498  $499,125	$919  $-  $594  $2,314	$(919) $-  $-  $(501)	$161,247  $869  $5,092  $500,938

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

In this section we discuss the general financial condition and results of operations for Central Vermont Public Service Corporation (the "Company" or "we" or "our" or "us") and its subsidiaries. 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;
• 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;
• ability to maintain or improve our current credit ratings; and
• other considerations such as the operations of ISO-New England, changes in the cost or availability of capital, authoritative accounting guidance and the effect of the volatility in the equity markets on pension benefit and other costs.

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. We typically generate most of our earnings through retail electricity sales. We also sell excess power, if any, to third parties in New England and to ISO-New England. The resale revenue generated from these sales helps to mitigate our power supply costs which comprise almost 60 percent of our annual operating expenses. 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.

Our consolidated earnings for the second quarter were $0.5 million, or 4 cents per diluted share of common stock, and $6.2 million, or 58 cents per diluted share of common stock for the first six months of 2007. This compares to consolidated earnings of $1.0 million, or 8 cents per diluted share of common stock for the second quarter, and $5.1 million, or 43 cents per diluted share of common stock for the first six months of 2006. Our earnings for the second quarter and first six months of 2007 were affected by incremental service restoration costs of about $3.2 million, or 18 cents per diluted share, resulting from a major storm in April 2007. More than 40 percent of our customers lost power, and many customers remained without power for two or more days. The primary drivers of the earnings variances for the second quarter and first six months of 2007 are described in Results of Operations below.

We are continuing to focus on the following strategic financial initiatives:

1. Restoring our corporate credit rating to investment-grade status.
2. Ensuring that our retail rates are set at levels to recover our costs of service. In May we filed for a 4.46 percent rate increase, and we are also continuing to assess opportunities for alternative regulation. See Retail Rates below.
3. Evaluating financing options so that we can continue to invest in Vermont Transco LLC ("Transco"), which was formed in June 2006 by Vermont Electric Power Company Inc. ("VELCO") and its owners, including us, for construction, maintenance and operation of transmission facilities in Vermont. See Liquidity and Capital Resources.
4. Planning for replacement power when our long-term power contracts with Vermont Yankee Nuclear Power Corporation ("VYNPC") and Hydro-Quebec expire. See Power Supply Matters below.

What follows is a discussion of our results of operations and certain business risks including cash flow risks, regulatory risks and power supply risks.

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RETAIL RATES

On December 7, 2006, the PSB issued an Order ("2006 Rate Order") approving a 4.07 percent rate increase effective January 1, 2007. The 2006 Rate Order provided, among other things, an allowed rate of return on common equity of 10.75 percent capped until our next rate proceeding. The rate increase, net of amounts to be returned to customers as described below, will add revenue of approximately $9.9 million annually.

On January 12, 2007, the PSB issued an Order denying our Accounting Order request for recovery of $1.5 million of incremental replacement power costs associated with a 2005 Vermont Yankee refueling outage. Pursuant to the 2006 Rate Order, because the 4.07 percent rate increase included recovery of the incremental replacement power costs, we began deferring $1.5 million of revenue over two years, and will continue such deferral until our next rate proceeding, at which time the total amount deferred will be returned to customers. As of June 30, 2007, we deferred $0.4 million as a liability with an offsetting reduction in operating revenue.

On May 15, 2007, we filed a request for a 4.46 percent rate increase (additional revenue of about $12.4 million on an annual basis), to be effective February 1, 2008.  Our rate increase request reflects expected increases in operating costs including among other things, purchased power and transmission, and increases in return on rate base related to additional investments in plant and Transco. The case is proceeding pursuant to an agreed-upon schedule, and a decision is expected in late January 2008.  We cannot predict the outcome at this time.

During the second quarter of 2007, we continued to analyze alternative regulation plans that have been approved by the PSB for two other Vermont utilities. If we conclude that an acceptable alternative regulation plan is feasible, we may file a petition asking the PSB for approval of our plan.

On April 25, 2007, the PSB approved the rate design agreement that we had previously reached with the Vermont Department of Public Service ("DPS"). The rate design became effective for bills rendered on or after July 1, 2007, except for one rate class change with implementation delayed until September 1, 2007. The rate design results in a modest reallocation of revenue by customer class with greater emphasis on energy charges in reaction to wholesale market energy costs. The rate design agreement also included a comprehensive study of the need for new service offerings and further rate redesign given certain fundamental changes in how costs are incurred to serve load based on availability of advanced metering and communications and structural changes in the New England wholesale power market. The study is due to the PSB in April 2008.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows At June 30, 2007, we had cash and cash equivalents of $4.2 million included in total working capital of $3.9 million. At June 30, 2006, we had cash and cash equivalents of $10.7 million included in total working capital of $26.6 million. 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 $8.6 million in the first six months of 2007. 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, reflecting our investments in Transco. 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. Changes in working capital and other items used $5.6 million. This was primarily due to $7.9 million of employee benefit funding, including $6.5 million of pension and postretirement medical trust fund contributions, and $5.1 million of income tax payments and $4.0 million of interest payments.

During the first six months of 2006, Operating activities provided $12.7 million. Net income, when adjusted for depreciation, amortization, deferred income tax and other items provided $18.2 million. This included $0.9 million of distributions received from affiliates. Additionally, collateral requirements under certain power contracts decreased by $7.4 million and changes in working capital and other items used $12.9 million. This was primarily related to $17.6 million of employee benefit funding, including $16.3 million of pension and postretirement medical trust fund contributions.

Investing Activities: Investing activities used $9.6 million in the first six months of 2007, including $9.8 million for construction and plant expenditures, partially offset by $0.2 million from other investments. During 2006, Investing activities provided $47.8 million, including $66.3 million in proceeds from net sales and maturities of available-for-sale

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securities. We sold about $50.0 million of available-for-sale securities for the purchase of shares of our common stock through our tender offer that concluded in April 2006. We used about $9.5 million for construction expenditures and $8.9 million for our investment in Transco.

Financing Activities: Financing activities provided $2.4 million in the first six months of 2007, including $1.0 million from stock option exercises and a $1.0 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, $1.0 million for preferred stock sinking fund payments and $0.4 million for capital lease payments. During 2006, Financing activities used $56.4 million, including $51.2 million for the tender offer, $5.5 million for dividends paid on common and preferred stock and $0.5 million for capital lease payments. These items were partially offset by $0.7 million from stock issuance proceeds resulting from stock option exercises.

Transco Based on current projections, Transco expects to need additional capital over the 2007 to 2010 timeframe, but its projections are subject to change based on a number of factors, including revised construction project estimates, timing of regulatory project approvals, 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. Based on Transco's current projections we could have an opportunity to make additional investments of $50.0 million to $65.0 million in the fourth quarter of 2007, but the timing and amount depend on Transco's regulatory schedule and the amounts invested by other owners. We are currently considering issuance of subordinated debt to fund these investments, but any additional investments that we make in Transco are subject to available capital and appropriate approvals.

Cash Flow Risks We believe that cash on hand, cash flow from operations and our $25.0 million credit facility will be sufficient to fund our business. Based on our current cash forecasts, we believe the borrowing capacity under the credit facility will provide sufficient liquidity through the end of 2008. However, an extended unplanned Vermont Yankee plant outage or similar event could significantly impact 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 largely due to lower-than-anticipated margins on sales revenue from excess power or an unexpected pow er source interruption; required prepayments for power purchases; and increases in performance assurance requirements.

Financing We have a three-year $25.0 million unsecured revolving-credit facility with a lending institution pursuant to a Credit Agreement dated October 21, 2005. We make periodic short-term borrowings under the revolving credit facility to manage our working capital requirements. At June 30, 2007, $6.5 million of borrowings were outstanding under this facility. This amount was repaid in early July. Also, in June letters of credit totaling $6.0 million were issued under the facility to support certain power-related performance assurance requirements.

At June 30, 2007, 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.

Performance Assurance At June 30, 2007, we had posted $5.2 million of collateral under performance assurance requirements for certain of our power contracts. In early July we replaced the majority of collateral with letters of credit as described above. We are subject to performance assurance requirements for power purchase and sale transactions through ISO-New England under the Financial Assurance Policy for NEPOOL members. Our credit limit with ISO-New England is zero and we are required to post collateral for all net purchase transactions. We are subject to performance assurance requirements for power purchase and sale transactions through ISO-New York, but activity in this market has been limited. Additionally, we are currently 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.

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.

Pension and Postretirement Medical Benefit Trust Fund Contributions In June 2007, we contributed $4.1 million to our pension trust fund and $2.5 million to our postretirement medical trust funds. We do not plan on making any additional contributions to these trust funds in 2007.

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Dividend Reinvestment Plan Our Dividend Reinvestment Plan was reinstated in April 2007. At that time, we elected to change our source of common shares to meet reinvestment needs under the Plan from open market purchases to Original Issue shares. Beginning in July 2007, we will use Treasury shares to meet reinvestment needs under the Plan. These elections will result in additional cash flows of $1.0 million to $2.0 million annually.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our financial statements are prepared in accordance with generally accepted accounting principles in the United States ("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 2006 Annual Report on Form 10-K. The following is an update.

Regulatory Accounting We prepare our financial statements in accordance with SFAS No. 71, Accounting for the Effects of Certain Types of Regulation ("SFAS No. 71") for our regulated business. The application of SFAS No. 71 results in differences in the timing and recognition of certain revenues and expenses from those of other businesses and industries. We continuously review regulatory assets and other deferred charges to assess ultimate recoverability through retail rates. Based on a current evaluation of the factors and conditions expected to affect future cost recovery, we believe future recovery of regulatory assets is probable. In the event that we determine our regulated operations no longer meet the criteria under SFAS No. 71 and there is not a rate mechanism to recover these costs, we would be required to write off, as an extraordinary charge to operations, net regulatory assets of $20.1 million on a pre-tax basis as of June 30, 2007. We would also be required to record pe nsion and postretirement medical benefit costs of $30.4 million on a pre-tax basis to Accumulated Other

Comprehensive Loss as a reduction in stockholder's equity, and would be required to determine any potential impairment to the carrying costs of deregulated plant. Risks associated with recovery of regulatory assets relate to potentially adverse legislation, and judicial or regulatory actions in the future.

Derivative Financial Instruments At December 31, 2006, our power contracts that are derivatives included: 1) one long-term purchased power contract that allows the seller to repurchase specified amounts of power with advance notice (Hydro-Quebec Sellback #3); 2) one long-term forward sale contract; and 3) one short-term forward purchase contract. During the first six months of 2007, the short-term forward purchase contract ended, and we entered into four additional power contract derivatives including three short-term forward sale contracts and one forward purchase contract for purchases during the scheduled Vermont Yankee plant outage in 2008. 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. The estimated fair values of power contract derivatives are based on over-the-counter quotations or broker quotes at the end of the reporting period, except for Hydro-Quebec Sellback #3, which is valued using a binomial tree model and quoted market data when available, along with appropriate valuation methodologies.

At June 30, 2007, the estimated fair value of three of the six power contract derivatives was an unrealized loss of $7.9 million and the estimated fair value of the remaining three was an unrealized gain of $0.5 million. At December 31, 2006, the estimated fair value of all power contract derivatives was an unrealized loss of $8.0 million. 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 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.

Income Taxes In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109 ("FIN 48"). FIN 48 clarifies the methodology to be used in estimating and reporting amounts associated with uncertain tax positions, including interest and penalties. We adopted FIN 48 on January 1, 2007 as required, and it did not have a material impact on our results of operations or statement of financial position. However, the application of income tax law is complex and we are required to make many subjective assumptions and judgments regarding our income tax exposures. Changes in our subjective assumptions and judgments can materially affect amounts recognized on the income statement and balance sheet.

In the second quarter of 2007, management determined that it would file amended returns for the 2003 through 2006 tax years requesting refunds totaling $3.0 million. The basic issue is the independent application of Internal Revenue Code sections 162 and 165 and whether section 162 repair deductions may be taken concurrent with section 165 casualty losses. We have categorized this tax position as more likely than not to be sustained upon examination based on its technical merits, and recorded a $1.4 million FIN 48 liability in the second quarter of 2007. Because of the impact of deferred tax accounting the disallowance of this item would not affect the effective tax rate.

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RESULTS OF OPERATIONS

The following is a detailed discussion of the results of operations for the second quarter and first six months of 2007. This should be read in conjunction with the condensed consolidated financial statements and accompanying notes included herein.

Second quarter of 2007 net income decreased $0.5 million, or 4 cents per diluted share of common stock, compared to the second quarter of 2006. Net income for the first six months of 2007 increased $1.1 million, or 15 cents per diluted share of common stock, compared to the first six months of 2006. The table below provides a reconciliation of the primary year-over-year variances in diluted earnings per share.

	2007 versus 2006
	Three Months Ended June 30	Six Months Ended June 30
2006 Earnings per diluted share Year-over-Year Effects on Earnings (a):    Higher retail revenues - 4.07 percent rate increase Jan. 1, 2007    Higher retail revenues - volume    Lower purchased power costs    Higher equity in earnings    Lower resale sales    Higher maintenance costs due to Apr. 2007 major storm    Higher operating and other    Lower CRC earnings 2007 Earnings per diluted share	$.08  ..15  ..06  ..18  ..11  (.32) (.18) (.04)      -  $.04	$.43  ..32  ..27  ..19  ..21  (.43) (.18) (.21) (.02) $.58
(a) The favorable affects of the April 2006 stock buyback (1 cent in the second quarter and 8 cents in the first six      months of 2007) are included in the individual EPS variances and not shown separately in the table above.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	Revenue (in thousands)		mWh Sales		Revenue (in thousands)		mWh Sales
	2007	2006	2007	2006	2007	2006	2007	2006
Residential Commercial Industrial Other   Total retail sales Resale sales Provision for rate refund Other operating revenues Total operating revenues	$30,744  25,615  8,321        462   65,142  10,044  (186)     2,380  $77,380	$28,227  24,580  8,181        446  61,434  15,757  - -      1,801  $78,992	222,106  209,137  101,461      1,570  534,274  185,296  - -              -  719,570	214,537  208,896  101,632      1,541  526,606  312,804  - -              -  839,410	$68,449  52,763  18,559           912    140,683  19,651  (373)       4,115  $164,076	$61,901  49,583  17,882        882  130,248  27,295  - -      3,704  $161,247	509,694  433,809  219,839         3,107  1,166,449  360,279  - -                 -  1,526,728	481,482  425,555  216,452         3,051  1,126,540  527,619  - -                -  1,654,159

Operating revenue decreased $1.6 million in the second quarter and increased $2.8 million in the first six months of 2007 compared to the same periods in 2006 due to the following:

• Retail sales increased $3.7 million in the second quarter and $10.4 million in the first six months of 2007 resulting from a 4.07 percent retail rate increase as of January 1, 2007 and higher sales volume. The rate increase added $2.6 million to retail sales revenues in the second quarter and $5.6 million in the first six months of 2007. The increase in retail sales volume primarily resulted from small service territory acquisitions in the last half of 2006 and overall customer growth in each of our service territories.
• Resale sales decreased $5.7 million in the second quarter and $7.6 million in the first six months of 2007 resulting from less excess power available for resale compared to the same period in 2006. The decrease in power available for resale resulted from second-quarter 2007 scheduled refueling outages at Vermont Yankee and Millstone Unit #3, lower output from Independent Power Producers and our owned hydro facilities and increased retail sales volume. Also, the second quarter and first six months of 2006 included $3.9 million and $4.3 million, respectively, for the resale of Vermont Yankee uprate energy as described in Purchased Power below.

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• The provision for rate refund decreased revenue by $0.2 million in the second quarter and $0.4 million in the first six months of 2007. This is related to amounts included in the 4.07 percent rate increase to be refunded to customers because the PSB disallowed our request to recover $1.5 million of Vermont Yankee 2005 incremental refueling costs.
• Other operating revenues increased $0.6 million in the second quarter and $0.4 million in the first six months of 2007 resulting from higher transmission revenue including revenue from the sale of transmission capacity on our share of Phase I/II transmission facility rights, and true-up adjustments under the transmission tariffs. We expect the sale of Phase I/II transmission facility rights, which extends from April to December, to add about $1.3 million to transmission revenue in 2007.

Purchased Power Purchased power expense and related mWh purchases are summarized below.

	Three Months Ended June 30,				Six Months Ended June 30,
	Purchases (in thousands)		mWh Purchases		Purchases (in thousands)		mWh Purchases
	2007	2006	2007	2006	2007	2006	2007	2006
VYNPC (a) Hydro-Quebec Independent Power Producers   Subtotal long-term contracts Other purchases SFAS No. 5 loss amortizations Maine Yankee, Connecticut   Yankee and Yankee Atomic Other Total purchased power	$11,106  15,922      6,169  33,197  7,075  (299) 701        (855) $39,819	$19,495  15,566       6,269  41,330  179  (299) 1,542         231  $42,983	266,715 240,941   49,156 556,812 98,528 - -  - -             -   655,340	454,767 233,171    55,718 743,656 3,266 - -  - -            -  746,922	$27,061  32,655    12,355  72,071  9,844 (598) 1,385       (623) $82,079	$35,403  31,798   12,952  80,153  2,652  (598) 2,907         357  $85,471	653,711 508,483      93,800 1,255,994 130,245 - -  - -               -  1,386,239	847,252 488,686    106,412 1,442,350 28,641 - -  - -                -  1,470,991
(a) Six months ended June 30, 2007 and 2006 includes $0.5 million for our share of nuclear insurance settlements that we defer per a PSB Order.

Purchased power costs decreased $3.1 million in the second quarter and $3.4 million in the first six months of 2007 compared to the same periods in 2006 due to the following:

• Purchased power costs under long-term contracts decreased $8.1 million in second quarter and first six months of 2007 primarily resulting from a decrease in purchases from VYNPC due to a second-quarter 2007 scheduled refueling outage versus full production during the first six months of 2006 including additional uprate power that we were required to purchase at market prices. The additional uprate power that we purchased amounted to $3.9 million in the second quarter and $4.3 million in the first six months of 2006. That power was resold in the wholesale energy markets as described in Revenue above. Purchases from Independent Power Producers, most of which are hydro facilities, decreased resulting from less rainfall, partly offset by an increase in average rates. Purchases from Hydro-Quebec increased resulting from more scheduled deliveries at times of higher market prices.
• Other purchases increased $6.9 million in the second quarter and $7.2 million in the first six months of 2007 resulting from replacement energy purchased during the Vermont Yankee scheduled refueling outage, and less power available from our joint and wholly owned units including a second-quarter 2007 scheduled refueling outage at Millstone Unit #3 and lower output from our hydro facilities.
• Power costs associated with our ownership interests in Maine Yankee, Connecticut Yankee and Yankee Atomic decreased $0.8 million in the second quarter and $1.5 million in the first six months of 2007 resulting from lower collection schedules for Connecticut Yankee and Yankee Atomic decommissioning activities which are nearly complete.
• Other costs decreased $1.1 million in the second quarter and $1.0 million in the first six months of 2007 primarily resulting from accounting deferrals and amortizations related to Millstone Unit #3 scheduled refueling outages. Based on approved regulatory accounting treatment we defer the incremental energy costs related to scheduled refueling outages and amortize those costs until the next scheduled refueling outage.

Operating Expenses Excluding purchased power expense described above, operating expenses increased $3.0 million in the second quarter and $6.3 million in the first six months of 2007 compared to 2006. The variances in income statement line items that comprise operating expenses on the Condensed Consolidated Statements of Income are described below.

Production: Production operation costs increased $0.5 million for the second quarter and $0.8 million in the first six months of 2007 resulting from premium expense for Vermont Yankee outage insurance ($1.5 million amortized over 12-months beginning January 1, 2007) and higher fuel costs in the first quarter due to increased output from one of our jointly owned units.

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Transmission - affiliates: These expenses represent our share of the net cost of service of Transco (previously provided by VELCO) as well as 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 (so-called PTF) transmission facilities are collected from load-serving entities using the system and redistributed to the owners of the facilities, including Transco. There were no significant variances for the second quarter or first six months of 2007.

Transmission - other: The majority of these expenses are for purchases of regional transmission service under the NOATT and charges for the Phase I and II transmission facilities. These expenses increased $0.3 million in the second quarter and $1.0 million in the first six months of 2007 primarily from higher rates and overall transmission expansion in New England, partially offset by lower depreciation expense because the Phase I facility was fully depreciated in 2006.

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 expenses increased $0.1 million in the second quarter and $1.3 million in the first six months of 2007 resulting from 1) higher bad debt expense related to a customer bankruptcy and, in 2006, recovery of a previous charge-off; 2) higher incentive compensation accruals; and 3) higher other costs, including professional services. These were partially offset by lower pension and postretirement medical costs primarily due to additional contributions to the trust funds in March 2006, and lower external audit fees.

Maintenance: These expenses are related to costs associated with maintaining our electric distribution system and include costs from our jointly owned generating and transmission facilities. The increase of $3.1 million in the second quarter and first six months of 2007 included $3.2 million of storm restoration costs resulting from a major storm in April 2007.

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.

Other Income and Other Deductions These items are related to the non-operating activities of our utility business and the operating and non-operating activities of our non-regulated businesses through Catamount Energy Resources ("CRC"). CRC's earnings were $0.1 million in the second quarter and $0.3 million in the first six months of 2007 compared to $0.1 million in the second quarter and $0.6 million in the first six months of 2006. The variances in income statement line items that comprise other income and other deductions on the Condensed Consolidated Statements of Income are described below.

Equity in earnings: Equity in earnings increased $1.2 million in the second quarter and $2.4 million in the first six months of 2007, principally from our investment in Transco.

Other income: Other income decreased $0.4 million in the second quarter and $1.4 million in the first six months of 2007. This primarily resulted from two favorable items in 2006 including interest earned on cash proceeds from CRC's December 2005 sale of Catamount Energy Corporation and a gain on the sale of non-utility property. There were no comparable items in 2007.

Other deductions: Other deductions decreased $0.3 million in the second quarter and $0.4 million in the first six months of 2007. This was primarily due to stronger market performance of life insurance policies.

Benefit (provision) for income taxes:  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.

POWER SUPPLY AND TRANSMISSION MATTERS

Power Supply Risks Our material power supply contracts are with Hydro-Quebec and VYNPC. These contracts comprise the majority of our total annual energy (mWh) purchases. The contract for power purchases from VYNPC ends in 2012, and deliveries under the contract with Hydro-Quebec end in 2016 with the level of deliveries decreasing starting in 2012. These contracts are described in Note 7 - Commitments and Contingencies.

In January 2006, ENVY submitted a renewal application with the NRC for a 20-year extension of the Vermont Yankee plant operating license. ENVY will also need approval of the PSB to continue to operate beyond 2012. At this time, ENVY has not received approvals for the license extension, but in April 2007 it initiated a 30-day exclusive negotiation period required

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by the original 2002 Vermont Yankee Memorandum of Understanding with the State of Vermont, for potential power purchases by the VYNPC sponsor companies, including us, in the plant's post-March 2012 life extension period. While the 30-day exclusive negotiation period has ended, we are continuing to participate in negotiations for a power contract beyond 2012 and cannot determine the outcome at this time.

There may also be opportunities to negotiate with Hydro-Quebec for future power purchase contracts, and preliminary discussions have begun.

There is a risk that future sources available to replace these contracts may not be as reliable and may include different environmental considerations. Also, the price of such replacement power could be significantly higher than under the current contracts.

There is also a risk that the Vermont Yankee plant could be shut down earlier than expected if ENVY determines that it is not economical to continue operating the plant. Based on our projected market prices at June 30, 2007, the incremental cost of replacement power, including capacity, is estimated to average $55 million annually. We are not able to predict whether there will be an early shutdown of the Vermont Yankee plant or whether the PSB will allow timely and full recovery of increased costs related to any such shutdown. However, an early shutdown could materially affect our financial position and future results of operations if the costs are not recovered in retail rates in a timely fashion.

Power Supply Management We have entered into several forward sale contracts since January 1, 2007 due to forecasted energy excess during 2007 and 2008. The contracts vary from one to eight months and deliveries vary from 10 MW to 65 MW depending upon our forecast excesses in the on-peak and peak periods of each month. Some of the forward sale contracts are contingent on Vermont Yankee plant output, eliminating the risks related to sourcing the sale if Vermont Yankee is not operating. Others are firm, thus potentially exposing us to the risk of market price volatility if we are not able to source the contracts with existing resources. Our main supply risk is with Vermont Yankee, and we have outage insurance through December 2008 to mitigate the market price risk during an unplanned outage through that time.

The outage insurance for 2007 applies to unplanned Vermont Yankee plant outages of up to 30 consecutive calendar days per outage event, and provides for payment to us of the difference between the spot market price and $40/mWh. The total maximum coverage is $10.0 million, with a $1.0 million total deductible. In 2006, we paid a premium of about $1.3 million for this insurance coverage. There were no claims under this insurance contract during the first six months of 2007. In July 2007, we purchased outage insurance coverage for 2008 with terms that are similar to the outage insurance in place for 2007. The total maximum coverage is $12.0 million, with a $1.2 million total deductible. A small portion of the premium is due in August with the remainder due in December 2007.

In June 2007 we also entered into a forward contract for the purchase of replacement power during the scheduled Vermont Yankee plant outage in late 2008.

Some of the forward power contracts that we enter into are derivatives and therefore the fair value is recorded on the balance sheet. Based on PSB-approved regulatory accounting treatment, changes in the fair value are not included on our income statement. Also see Item 3 - Quantitative and Qualitative Disclosures about Market Risk.

Millstone Unit #3 We have a 1.73 joint-ownership percentage in Millstone Unit # 3. Dominion Nuclear Corporation ("DNC") is the lead owner with about 93.47 percent of the plant joint-ownership. During Millstone Unit #3's scheduled refueling outage that began on April 7, 2007, DNC announced that it had discovered indications of cracking in the first stage of the high-pressure turbine. The plant began producing power for the grid on May 19, 2007. DNC is continuing to evaluate options ranging from replacing the turbine to continued use in its current condition. We cannot predict the outcome of this matter at this time.

In January 2004, DNC filed, on behalf of itself and the two minority owners, including us, a lawsuit against the Department of Energy ("DOE") seeking recovery of costs related to storage of spent nuclear fuel arising from the failure of the DOE to comply with its obligations to commence accepting such fuel in 1998. A trial is expected to be held in August 2008. We continue to pay our share of the DOE Spent Fuel assessment expenses levied on actual generation and will share in recovery from the lawsuit, if any, in proportion to our ownership interest.

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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 of these nuclear plants have been permanently shut down and have completed or are nearing completion of decommissioning. We are responsible for paying our equity ownership percentage of decommissioning costs and all other costs for these plants. At June 30, 2007, based on the most recent estimates provided, our share of remaining costs is $2.8 million for Maine Yankee, $7.6 million for Connecticut Yankee and $3.2 million for Yankee Atomic. These amounts are recorded as nuclear decommissioning liabilities (current and non-current) on the balance sheet with a corresponding regulatory asset. We adjust associated regulatory assets and nuclear decommissioning liabilities when revised estimates are provided.

All three companies are involved in litigation with the DOE regarding storage of spent nuclear fuel. On September 30, 2006, the United States Court of Federal Claims issued a judgment in the spent fuel litigation and awarded damages to all three companies. On December 4, 2006, the DOE filed a notice of appeal to the United States Court of Appeals for the Federal Circuit ("Appeals Court") in all three cases, and on December 14, 2006, all three companies filed notices of cross appeals. In the first quarter of 2007, the Appeals Court issued an order consolidating the three cases, and issued an order making another case a companion appeal to the case, which will result in both appeals being heard consecutively.

Due to the complexity of the issues and the appeals, the three companies cannot predict the amount of damages that will actually be received or the timing of the final determination of such damages. Each of their respective FERC settlements require 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 payments, if any, would be credited to our ratepayers as well. Also see Note 3 - Investments in Affiliates for additional information regarding the DOE litigation.

New England Wholesale Energy Markets In December 2006, ISO-New England implemented a new market mechanism referred to as the Forward Capacity Market ("FCM") to compensate owners of new and existing generation capacity, including demand reduction. ISO-New England believes that higher capacity payments in constrained areas will encourage the development of new generation where needed. Capacity requirements for load serving entities, including us, are based on each entity's proportionate share of ISO-New England's prior year coincident peak demand. Based on current projections, we expect the FCM rules will result in an average capacity deficiency of about 35 MW for the rest of 2007, possibly increasing thereafter. Based on specified rates through May 2010, we expect net FCM charges of about $0.6 million for the remainder of 2007 and $1.5 million or more in 2008 and 2009.

We continue to monitor potential changes to the rules in the wholesale energy markets in New England. Such changes could have a material impact on power supply costs.

Transmission As a load serving entity, we are required to share the costs related to the region's high voltage transmission system through payments made under NOATT. Our allocation of NOATT costs, based on our percentage of network load, is a small fraction of New England's obligation. While this regional cost-sharing approach reduces our costs related to qualifying Vermont transmission upgrades, we pay a share of the costs for new and existing NOATT-qualifying facilities located elsewhere in New England.

There are a number of major transmission projects in Vermont being undertaken by Transco, some of which are already in service. Many of these projects, including most of the so-called Northwest Reliability Project, have been approved by NEPOOL for NOATT cost sharing treatment. However, certain future Vermont transmission facilities may not qualify for such cost sharing, and those costs will be charged locally (within Vermont) rather than regionally. Our share of such costs will be determined by the classification of each project; some will be charged directly to specific utilities and some will be shared by all Vermont utilities.

Transmission services provided by Transco are billed to us under the 1991 Transmission Agreement also referred to as the Vermont Transmission Agreement ("VTA"). We and 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 requests by Transco for revisions to the VTA. Hearings on these proceedings are scheduled to begin in January 2008. Additionally, the parties to these proceedings, including us, have and continue to participate in settlement negotiations. We are not able to predict the outcome of this matter at this time.

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RECENT ENERGY POLICY INITIATIVES

The State of Vermont continues to examine changes to the provision of electric service absent introduction of retail choice. Several laws have been passed since 2005 that impact electric utilities in Vermont. These include: 1) Act 61 - Renewable Energy, Efficiency, Transmission, and Vermont's Energy Future; 2) Act 208 - Vermont Energy Security and Reliability Act; and 3) Act 123 - Regional Greenhouse Gas Initiative. The major provisions of the new laws that could affect our business are described in our 2006 Annual Report on Form 10-K.

While provisions of recently passed laws are now being implemented, there is continued interest in new policies designed to reduce electricity consumption, promote renewable energy and reduce greenhouse gas emissions. In May, the Vermont Legislature passed an energy bill, but it was vetoed by the governor and the veto was sustained during a special legislative session. We expect continued discussion of these matters during the remaining months of 2007, both informally and formally. A broad public engagement process by the DPS will begin this fall to better understand Vermonters views on energy issues, with a report due in December.

RECENT ACCOUNTING PRONOUNCEMENTS

See Note 1 - Summary of Significant Accounting Policies in the accompanying Condensed Consolidated Financial Statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Fair and adequate rate relief through cost-based rate regulation can limit our exposure to market volatility. Except as discussed below, there were no material changes from the disclosures in our Annual Report on Form 10-K for the year ended December 31, 2006.

At June 30, 2007, we had three power contract derivatives with a total estimated fair value of an unrealized loss of $7.9 million, and three with an estimated fair value of an unrealized gain of $0.5 million. Based on PSB-approved regulatory accounting treatment, changes in the fair value of derivatives are recorded on the balance sheet and do not impact our income statement. Summary information related to the fair value of these derivatives is shown in the table below (in thousands):

	Forward Sale Contracts	Forward Purchase Contracts	Hydro-Quebec Sellback #3
Total fair value at December 31, 2006 - unrealized loss    Change in fair value, including amounts settled Fair value of new derivatives at March 31, 2007 - unrealized loss    Change in fair value, including amounts settled Fair value of new derivatives at June 30, 2007 - unrealized loss Total fair value at June 30, 2007 - unrealized loss, net	$(3,962) 120  (422) 969             -  $(3,295)	$(304) 304  - -  - -   (502) $(502)	$(3,731) 171  - -  - -             -  $(3,560)
Source	Over-the-counter- quotations	Over-the-counter- quotations	Quoted market data & valuation methodologies
Estimated fair value for changes in projected market price:    10 percent increase    10 percent decrease	$(5,320) $(1,270)	$3  $(1,006)	$(7,797) $(1,268)

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures As of the quarter ended June 30, 2007, 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, 2007 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

Page 27 of 30

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, 2006, 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 6.		Exhibits.
	(a)		List of Exhibits
			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.

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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, Principal Financial Officer, and Treasurer

Dated  August 8, 2007

Page 29 of 30

EXHIBIT INDEX
Exhibit Number	Exhibit Description
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 30 of 30

EX-31

EXHIBIT 31.1 ANNUAL CERTIFICATION OF CHIEF EXECUTIVE OFFICER REQUIRED BY SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Robert H. Young, certify that:
1.	I have reviewed this quarterly report on Form 10-Q of Central Vermont Public Service Corporation (the "registrant");
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
	a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: August 8, 2007   /s/ Robert H. Young     Robert H. Young Chief Executive Officer

EX-31

EXHIBIT 31.2 ANNUAL CERTIFICATION OF CHIEF EXECUTIVE OFFICER REQUIRED BY SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Pamela J. Keefe, certify that:
1.	I have reviewed this quarterly report on Form 10-Q of Central Vermont Public Service Corporation (the "registrant");
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
	a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: August 8, 2007   /s/ Pamela J. Keefe    Pamela J. Keefe Chief Financial Officer

EX-32

EXHIBIT 32.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

            In connection with the Quarterly Report of Central Vermont Public Service Corporation (the "Company") on Form 10-Q for the period ended June 30, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I Robert H. Young, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge and belief:

            (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

            (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

  /s/ Robert H. Young   
Robert H. Young
Chief Executive Officer
August 8, 2007

A signed original of this written statement required by Section 906 has been provided to Central Vermont Public Service Corporation ("CVPS") and will be retained by CVPS and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32

EXHIBIT 32.2

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

            In connection with the Quarterly Report of Central Vermont Public Service Corporation (the "Company") on Form 10-Q for the period ended June 30, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I Pamela J. Keefe, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge and belief:

            (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

            (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

  /s/ Pamela J. Keefe     
Pamela J. Keefe
Chief Financial Officer
August 8, 2007

A signed original of this written statement required by Section 906 has been provided to Central Vermont Public Service Corporation ("CVPS") and will be retained by CVPS and furnished to the Securities and Exchange Commission or its staff upon request.