- Quarterly Report (10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)
x	QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 2010
or
¨	TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to

Commission file number 1-8222

Central Vermont Public Service Corporation

(Exact name of registrant as specified in its charter)

Vermont (State or other jurisdiction of incorporation or organization)	03-0111290 (IRS Employer Identification No.)
77 Grove Street, Rutland, Vermont (Address of principal executive offices)	05701 (Zip Code)
Registrant's telephone number, including area code (800) 649-2877
N/A (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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. As of July 31, 2010 there were outstanding 12,513,610 shares of Common Stock, $6 Par Value.

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Form 10-Q for Period Ended June 30, 2010

Table of Contents

PART I. Financial Information:
				Page
	Item 1.	Financial Statements
			Condensed Consolidated Statements of Income	2
			Condensed Consolidated Statements of Comprehensive Income	3
			Condensed Consolidated Statements of Cash Flows	4
			Condensed Consolidated Balance Sheets	5
			Condensed Consolidated Statement of Changes in Common Stock Equity	7
			Notes to Condensed Consolidated Financial Statements	8

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		28

	Item 3.	Quantitative and Qualitative Disclosures about Market Risk		41

	Item 4.	Controls and Procedures		42

PART II. Other Information:

	Item 1.	Legal Proceedings		43

	Item 1A.	Risk Factors		43

	Item 6.	Exhibits		43

SIGNATURES				44

Page 1 of 44

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(dollars in thousands, except per share data)
(unaudited)

	Three Months Ended June 30						Six Months Ended June 30
	2010			2009			2010			2009
Operating Revenues	$	79,937		$	82,627		$	170,944		$	173,354

Operating Expenses
Purchased Power - affiliates		10,514			16,034			27,072			32,096
Purchased Power		26,697			22,571			51,857			48,119
Production		2,660			2,766			5,616			5,986
Transmission - affiliates		1,668			2,989			3,054			5,470
Transmission - other		6,058			5,065			13,245			10,760
Other operation		15,836			14,089			31,682			29,622
Maintenance		7,392			5,549			15,118			10,041
Depreciation		4,330			4,163			8,682			8,192
Taxes other than income		4,470			3,878			9,213			8,046
Income tax (benefit) expense		(791	)		760			1,047			3,636
Total Operating Expenses		78,834			77,864			166,586			161,968

Utility Operating Income		1,103			4,763			4,358			11,386

Other Income
Equity in earnings of affiliates		5,115			4,431			10,510			8,876
Allowance for equity funds during construction		7			(19	)		10			131
Other income		721			748			1,433			1,481
Other deductions		(921	)		(108	)		(1,600	)		(878	)
Income tax expense		(1,714	)		(1,389	)		(3,303	)		(2,822	)
Total Other Income		3,208			3,663			7,050			6,788

Interest Expense
Interest on long-term debt		2,756			2,782			5,542			5,593
Other interest		115			178			226			297
Allowance for borrowed funds during construction		(5	)		(31	)		(7	)		(85	)
Total Interest Expense		2,866			2,929			5,761			5,805

Net Income		1,445			5,497			5,647			12,369
Dividends declared on preferred stock		92			92			184			184
Earnings available for common stock	$	1,353		$	5,405		$	5,463		$	12,185
Per Common Share Data:
Basic earnings per share	$	0.11		$	0.46		$	0.46		$	1.05
Diluted earnings per share	$	0.11		$	0.46		$	0.46		$	1.04

Average shares of common stock outstanding - basic		12,078,724			11,660,547			11,903,080			11,631,611
Average shares of common stock outstanding - diluted		12,109,591			11,684,149			11,933,923			11,669,823

Dividends declared per share of common stock	$	0.23		$	0.23		$	0.69		$	0.69
The accompanying notes are an integral part of these condensed consolidated financial statements.

Page 2 of 44

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(dollars in thousands)
(unaudited)
	Three months ended June 30				Six months ended June 30
	2010		2009		2010		2009

Net Income	$	1,445	$	5,497	$	5,647	$	12,369

Other comprehensive income, net of tax :

Defined benefit pension and postretirement medical plans:
Portion reclassified through amortizations, included in benefit costs and recognized in net income:
Actuarial losses, net of income taxes of $0, $0, $0 and $1		0		1		0		1
Prior service cost, net of income taxes of $0, $2, $0 and $5		0		3		0		7
Comprehensive income adjustments		0		4		0		8

Total comprehensive income	$	1,445	$	5,501	$	5,647	$	12,377

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

Page 3 of 44

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
(unaudited)
	Six months ended June 30
Cash flows provided (used) by:	2010			2009
OPERATING ACTIVITIES
Net income	$	5,647		$	12,369
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of affiliates		(10,510	)		(8,876	)
Distributions received from affiliates		6,639			5,259
Depreciation		8,682			8,192
Deferred income taxes and investment tax credits		1,600			2,738
Regulatory and other amortization, net		960			(592	)
Non-cash employee benefit plan costs		3,132			3,195
Other non-cash expense and (income), net		(744	)		3,121
Changes in assets and liabilities:
Decrease in accounts receivable and unbilled revenues		4,030			455
(Decrease) increase in accounts payable		(1,533	)		1,080
Change in prepaid and accrued income taxes		8,249			6,714
(Increase) decrease in other current assets		(1,291	)		1,447
Decrease (increase) in special deposits and restricted cash for power collateral		5,370			(1,005	)
Employee benefit plan funding		(152	)		(6,843	)
Decrease in other current liabilities		(2,583	)		(7,280	)
(Increase) decrease in other long-term assets and liabilities and other		(245	)		568
Net cash provided by operating activities		27,251			20,542
INVESTING ACTIVITIES
Construction and plant expenditures		(12,058	)		(12,893	)
Investments in available-for-sale securities		(935	)		(780	)
Proceeds from sale of available-for-sale securities		796			790
Other investing activities		(136	)		(340	)
Net cash used for investing activities		(12,333	)		(13,223	)
FINANCING ACTIVITIES
Net proceeds from the issuance of common stock		12,894			1,010
Retirement of preferred stock subject to mandatory redemption		(1,000	)		(1,000	)
Decrease in special deposits held for preferred stock redemptions		1,000			1,000
Common and preferred dividends paid		(5,634	)		(5,531	)
Proceeds from revolving credit facilities		82,388			13,395
Repayments under revolving credit facility		(103,130	)		(13,395	)
Common stock offering costs		(305	)		(54	)
Other financing activities		(556	)		(508	)
Net cash used by financing activities		(14,343	)		(5,083	)
Net increase in cash and cash equivalents		575			2,236
Cash and cash equivalents at beginning of the period		2,069			6,722
Cash and cash equivalents at end of the period	$	2,644		$	8,958

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

Page 4 of 44

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(dollars in thousands, except share data)
(unaudited)

	June 30, 2010		December 31, 2009
ASSETS
Utility plant
Utility plant, at original cost	$	602,867	$	593,211
Less accumulated depreciation		262,119		254,858
Utility plant, at original cost, net of accumulated depreciation		340,748		338,353
Property under capital leases, net		4,790		5,302
Construction work-in-progress		11,101		10,235
Nuclear fuel, net		1,960		2,190
Total utility plant, net		358,599		356,080

Investments and other assets
Investments in affiliates		133,604		129,733
Non-utility property, less accumulated depreciation ($3,659 in 2010 and $3,661 in 2009)		1,894		1,900
Millstone decommissioning trust fund		4,889		5,082
Other		6,329		6,542
Total investments and other assets		146,716		143,257

Current assets
Cash and cash equivalents		2,644		2,069
Restricted cash		0		5,369
Special deposits		6		1,007
Accounts receivable, less allowance for uncollectible accounts ($3,459 in 2010 and $3,577 in 2009)		24,052		24,597
Accounts receivable - affiliates, less allowance for uncollectible accounts		38		40
Unbilled revenues		16,716		20,827
Materials and supplies, at average cost		6,273		6,219
Prepayments		7,720		14,055
Deferred income taxes		3,532		3,351
Power-related derivatives		2,829		622
Other current assets		2,968		2,252
Total current assets		66,778		80,408

Deferred charges and other assets
Regulatory assets		47,073		46,240
Other deferred charges - regulatory		849		1,544
Other deferred charges and other assets		3,069		4,623
Total deferred charges and other assets		50,991		52,407

TOTAL ASSETS	$	623,084	$	632,152

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

Page 5 of 44

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(dollars in thousands, except share data)
(unaudited)

	June 30, 2010			December 31, 2009
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock, $6 par value, 19,000,000 shares authorized, 14,507,136 issued and 12,378,063 outstanding at June 30, 2010 and 13,835,968 issued and 11,706,895 outstanding at December 31, 2009	$	87,043		$	83,016
Other paid-in capital		80,872			72,179
Accumulated other comprehensive loss		(209	)		(209	)
Treasury stock, at cost, 2,129,073 shares at June 30, 2010 and December 31, 2009		(48,436	)		(48,436	)
Retained earnings		122,068			124,873
Total common stock equity		241,338			231,423
Preferred and preference stock not subject to mandatory redemption		8,054			8,054
Long-term debt		160,869			201,611
Capital lease obligations		3,837			4,313
Total capitalization		414,098			445,401

Current liabilities
Current portion of preferred stock subject to mandatory redemption		0			1,000
Current portion of long-term debt		20,000			0
Accounts payable		8,456			9,016
Accounts payable - affiliates		10,798			12,040
Nuclear decommissioning costs		1,557			1,443
Power-related derivatives		0			219
Other current liabilities		25,108			26,450
Total current liabilities		65,919			50,168

Deferred credits and other liabilities
Deferred income taxes		63,291			59,215
Deferred investment tax credits		2,514			2,642
Nuclear decommissioning costs		6,258			7,055
Asset retirement obligations		3,342			3,247
Accrued pension and benefit obligations		40,077			38,056
Power-related derivatives		0			149
Other deferred credits - regulatory		5,510			3,888
Other deferred credits and other liabilities		22,075			22,331
Total deferred credits and other liabilities		143,067			136,583

Commitments and contingencies

TOTAL CAPITALIZATION AND LIABILITIES	$	623,084		$	632,152

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

Page 6 of 44

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN COMMON STOCK EQUITY
(in thousands, except share data)
(unaudited)

	Common Stock				Treasury Stock
														Accumulated
											Other			Other
	Shares										Paid-in			Comprehensive			Retained
	Issued		Amount		Shares			Amount			Capital			Loss			Earnings			Total
Balance, December 31, 2009		13,835,968	$	83,016		(2,129,073	)	$	(48,436	)	$	72,179		$	(209	)	$	124,873		$	231,423
Net income																		5,647			5,647
Common Stock Issuance, net of issuance costs		582,831		3,497								8,039									11,536
Dividend reinvestment plan		35,632		214								501									715
Stock options exercised		35,100		210								301									511
Share-based compensation:																					0
Common & nonvested shares		2,484		15								40									55
Performance share plans		15,121		91								(198	)								(107	)
Dividends declared:																					0
Common - $0.69 per share																		(8,266	)		(8,266	)
Cumulative non-redeemable preferred stock																		(184	)		(184	)
Amortization of preferred stock issuance expense												8									8
Gain (Loss) on capital stock												2						(2	)		0
Balance, June 30, 2010		14,507,136	$	87,043		(2,129,073	)	$	(48,436	)	$	80,872		$	(209	)	$	122,068		$	241,338

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

Page 7 of 44

CENTRAL VERMONT PUBLIC SERVICE CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - BUSINESS ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General Description of Business Central Vermont Public Service Corporation (“we”, “us”, “CVPS” or the “company”) is the largest electric utility in Vermont. We engage principally in the purchase, production, transmission, distribution and sale of electricity. We serve approximately 159,000 customers in 163 of the towns and cities in Vermont. Our Vermont utility operation is our core business. We typically generate most of our revenues through retail electricity sales. We also sell excess power, if any, to third parties in New England and to ISO-New England, the operator of the region’s bulk power system and wholesale electricity markets. The resale revenue generated from these sales helps to mitigate our power supply costs.

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

Basis of Presentation These unaudited interim financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, certain information and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) have been condensed or omitted. The accompanying unaudited condensed consolidated interim financial statements contain all normal, recurring adjustments considered necessary to present fairly the financial position as of June 30, 2010, the results of operations for the three-month and six-month periods ended June 30, 2010 and 2009 and cash flows for the six-month periods ended June 30, 2010 and 2009. The results of operations for the interim periods presented herein may not be indicative of the results that may be expected for the full year. These financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2009.

Regulatory Accounting Our utility operations are regulated by the Vermont Public Service Board (“PSB”), the Connecticut Department of Public Utility and Control and the Federal Energy Regulatory Commission (“FERC”), with respect to rates charged for service, accounting, financing and other matters pertaining to regulated operations. As required, we prepare our financial statements in accordance with the Financial Accounting Standards Board’s (“FASB”) guidance for regulated operations. The application of this guidance results in differences in the timing of recognition of certain expenses from those of other businesses and industries. In order for us to report our results under the accounting for regulated operations, our rates must be designed to recover our costs of providing service, and we must be able to collect those rates from customers. If rate recovery of the majority of these costs becomes unlikely or uncertain, whether due to competition or regulatory action, we would reassess whether this accounting standard would continue to apply to our regulated operations. In the event we determine that we no longer meet the criteria for applying the accounting for regulated operations, the accounting impact would be a charge to operations of an amount that would be material unless stranded cost recovery is allowed through a rate mechanism. Based on a current evaluation of the factors and conditions expected to impact future cost recovery, we believe future recovery of our regulatory assets is probable. Criteria that could give rise to the discontinuance of accounting for regulated operations 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. In the event that we no longer meet the criteria under the guidance for regulated operations and there is not a rate mechanism to recover these costs, the impact would, among other things, result in a charge to operations of $9.4 million pre-tax at June 30, 2010. See Note 7 - Retail Rates and Regulatory Accounting for additional information.

Derivative Financial Instruments We account for certain power contracts as derivatives under the provisions of FASB’s guidance for derivatives and hedging. This guidance requires that derivatives be recorded on the balance sheet at fair value. Our derivative financial instruments are related to managing our power supply resources to serve our customers, and are not for trading purposes. Contracts that qualify for the normal purchase and sale exception are not included in derivative assets and liabilities. Additionally, we have not elected hedge accounting for our power-related derivatives.

Page 8 of 44

Based on a PSB-approved Accounting Order, we record the changes in fair value of all power-related derivative financial instruments as deferred charges or deferred credits on the balance sheet, depending on whether the change in fair value is an unrealized loss or gain. The corresponding offsets are recorded as current and long-term assets or liabilities depending on the duration of the contracts. Realized gains and losses on sales are recorded as increases to or reductions of operating revenues, respectively. For purchase contracts, realized gains and losses are recorded as reductions of or additions to purchased power expense, respectively.

Our power-related derivatives include one forward energy contract, one long-term purchased power contract that allows the seller to repurchase specified amounts of power with advance notice (“Hydro-Quebec Sellback #3”) and financial transmission rights. All of our power-related derivatives are commodity contracts. For additional information about power-related derivatives, see Note 5 - Fair Value and Note 10 - Power-related Derivatives.

Government Grants We recognize government grants when there is reasonable assurance that we will comply with the conditions attached to the grant arrangement and the grant will be received. Government grants are recognized in the Condensed Consolidated Statements of Income over the periods in which we recognize the related costs for which the government grant is intended to compensate. When government grants are related to reimbursements of operating expenses, the grants are recognized as a reduction of the related expense in the Condensed Consolidated Statements of Income. For government grants related to reimbursements of capital expenditures, the grants are recognized as a reduction of the basis of the asset and recognized in the Condensed Consolidated Statements of Income over the estimated useful life of the depreciable asset as reduced depreciation expense.

We record government grants receivable in the Condensed Consolidated Balance Sheets in Prepayments and other current assets or other assets, depending on when the amounts are expected to be received from the government agency. Proceeds are expected to be received from government grants as reimbursement for expenditures made. To date, no costs have been deferred and no reimbursements have been received.

Our 2010 Base Rate filing included costs that are eligible for government grant reimbursement by the United States Department of Energy (“DOE”) under the American Recovery and Reinvestment Act; however, the grant reimbursement was not reflected in the base rate filing. Grant reimbursement of these 2010 costs will be charged to a regulatory liability and returned to customers in our next base rate filing.

Recently Adopted Accounting Policies

Variable Interest Entities: In June 2009, the FASB issued additional consolidation guidance related to variable interest entities and includes the addition of entities previously considered qualifying special-purpose entities.

We have an equity investment in and long term power purchase agreement (“PPA”) with VYNPC. VYNPC has a power purchase agreement with Entergy-Vermont Yankee, the owner of the Vermont Yankee nuclear plant, and VYNPC purchases 83 percent of the total output of the plant. Under the PPA with VYNPC, we purchase our entitlement share of the output of the plant, which is 29 percent of the total plant output. We have evaluated our equity investment and the power purchase agreement with VYNPC under the FASB variable interest accounting guidance and have determined that they both represent variable interests. We are not considered the primary beneficiary of VYNPC; therefore, are not required to consolidate VYNPC because we do not control the activities that are most relevant to the operating results of VYNPC.

We have an equity investment in and receive transmission services from Transco. The transmission services are billed under the 1991 Transmission Agreement (“VTA”). All of the Vermont utilities are parties to the VTA and the VTA requires the Vermont utilities to pay their pro-rata share of Transco’s costs, including interest and a fixed rate of return on equity, less the revenues collected under the ISO-New England Open Access Transmission Tariff. We have evaluated our equity investment and the VTA with Transco under the FASB variable interest accounting guidance and have determined that both represent variable interests. We are not considered the primary beneficiary of Transco; therefore, we are not required to consolidate Transco because we do not control the activities that are most relevant to the operating results of Transco.

Our maximum exposure to loss is the amount of our equity investments in Transco and VYNPC. See Note 3 – Investments in Affiliates.

The amended guidance did not have an impact on our financial position, results of operations and cash flows. The guidance became effective for us on January 1, 2010.

Page 9 of 44

NOTE 2 - EARNINGS PER SHARE (“EPS”)

The Condensed Consolidated Statements of Income include basic and diluted per share information. Basic EPS is calculated by dividing net income, after preferred dividends, by the weighted-average number of common shares outstanding for the period. Diluted EPS follows a similar calculation except that the weighted-average number of common shares is increased by the number of potentially dilutive common shares. The table below provides a reconciliation of the numerator and denominator used in calculating basic and diluted EPS (dollars in thousands, except share information):

	Three months ended June 30						Six months ended June 30
	2010			2009			2010			2009
Numerator for basic and diluted EPS:
Net income	$	1,445		$	5,497		$	5,647		$	12,369
Dividends declared on preferred stock		(92	)		(92	)		(184	)		(184	)
Net income available for common stock	$	1,353		$	5,405		$	5,463		$	12,185

Denominators for basic and diluted EPS:
Weighted-average basic shares of common stock outstanding		12,078,724			11,660,547			11,903,080			11,631,611
Dilutive effect of stock options		14,657			8,925			15,899			24,026
Dilutive effect of performance shares		16,210			14,677			14,944			14,186
Weighted-average diluted shares of common stock outstanding		12,109,591			11,684,149			11,933,923			11,669,823

Outstanding stock options totaling 15,988 for the second quarter and 47,577 for the first six months were excluded from the computation of 2010 because the exercise prices were above the current average market price of the common shares. In 2009, outstanding stock options totaling 271,697 for the second quarter and 160,517 for the first six months were excluded from the computation because the exercise prices were above the current average market price of the common shares. Outstanding performance shares totaling 60,445 for the second quarter and first six months of 2010 were excluded from the diluted EPS calculation as either the performance share measures were not met or there was an antidilutive impact as of June 30, 2010. All performance shares were included in the computation in the second quarter and first six months of 2009.

NOTE 3 - INVESTMENTS IN AFFILIATES

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

	Three months ended June 30						Six months ended June 30
	2010			2009			2010			2009

Operating revenues	$	25,429		$	22,910		$	51,202		$	46,657
Operating income	$	14,050		$	12,474		$	28,987		$	24,789

Net income	$	12,435		$	10,451		$	24,970		$	21,423
Less net income attributable to non-controlling interests		11,455			9,213			22,905			18,286
Less income tax		560			202			526			1,211
Net income attributable to VELCO	$	420		$	1,036		$	1,539		$	1,926

Company's common stock ownership interest		47.05	%		47.05	%		47.05	%		47.05	%
Company's equity in net income	$	198		$	487		$	674		$	901

Accounts payable to VELCO were $5.1 million at June 30, 2010 and $5.6 million at December 31, 2009.

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

	Three months ended June 30						Six months ended June 30
	2010			2009			2010			2009

Operating revenues	$	25,852		$	22,786		$	52,017		$	46,407
Operating income	$	14,821		$	13,002		$	30,279		$	26,000
Net income	$	13,082		$	10,890		$	26,160		$	21,623

Company's ownership interest		33.33	%		39.79	%		33.33	%		39.79	%
Company's equity in net income	$	4,841		$	3,905		$	9,698		$	7,873

Transmission services provided by Transco are billed to us under the 1991 Transmission Agreement (“VTA”). All Vermont electric utilities are parties to the VTA. This agreement requires the Vermont utilities to pay their pro rata share of Transco’s total costs, including interest and a fixed rate of return on equity, less the revenue collected under the ISO-New England Open Access Transmission Tariff and other agreements.

Transco’s billings to us primarily include the VTA and charges and reimbursements under the NEPOOL Open Access Transmission Tariff (“NOATT”). Included in Transco’s operating revenues above, are transmission services to us amounting to $1.7 million in the second quarter and $3.1 million in the first six months of 2010 and $3 million in the second quarter and $5.5 million in the first six months of 2009. These amounts are reflected as Transmission - affiliates on our Condensed Consolidated Statements of Income. Accounts payable to Transco was a nominal amount at June 30, 2010 and $0.8 million at December 31, 2009.

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

	Three months ended June 30						Six months ended June 30
	2010			2009			2010			2009

Operating revenues	$	29,177		$	45,105		$	75,772		$	89,876
Operating (loss) income	$	(370	)	$	(845	)	$	(1,439	)	$	(1,819	)
Net income	$	125		$	58		$	226		$	152

Company's common stock ownership interest		58.85	%		58.85	%		58.85	%		58.85	%
Company's equity in net income	$	73		$	33		$	133		$	89

Included in VYNPC’s operating revenues above are sales to us of approximately $10.2 million in the second quarter and $26.4 million in the first six months of 2010 and $15.7 million in the second quarter and $31.4 million in the first six months of 2009. These are included in Purchased power - affiliates on our Condensed Consolidated Statements of Income. Accounts payable to VYNPC were $5.6 million at June 30, 2010 and December 31, 2009. Also see Note 12 - Commitments and Contingencies.

Maine Yankee, Connecticut Yankee and Yankee Atomic We own, through equity investments, 2 percent of Maine Yankee, 2 percent of Connecticut Yankee and 3.5 percent of Yankee Atomic. All three companies have completed plant decommissioning and the operating licenses have been amended by the Nuclear Regulatory Commission (“NRC”) for operation of Independent Spent Fuel Storage Installations. All three remain responsible for safe storage of the spent nuclear fuel and waste at the sites until the DOE meets its obligation to remove the material from the sites. Our share of the companies’ 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, 2010, we had regulatory assets of $0.9 million for Maine Yankee, $5.1 million for Connecticut Yankee and $1.9 million for Yankee Atomic. These estimated costs are being collected from customers through existing retail rate tariffs. Total billings from the three companies amounted to $0.4 million in the second quarter and $0.7 million in the first six months of 2010 and $0.3 million in the second quarter and $0.7 million in the first six months of 2009. These amounts are included in Purchased power - affiliates on our Condensed Consolidated Statements of Income.

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NOTE 4 - FINANCIAL INSTRUMENTS

The estimated fair values of financial instruments follow (dollars in thousands):

	June 30, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
Power contract derivative assets (includes current portion)	$	2,829	$	2,829	$	622	$	622
Power contract derivative liabilities (includes current portion)	$	0	$	0	$	368	$	368
Preferred stock subject to mandatory redemption (includes current portion)	$	0	$	0	$	1,000	$	1,000

Long-term debt:
First mortgage bonds (includes current portion)	$	167,500	$	192,418	$	167,500	$	186,210
Revenue bonds	$	10,800	$	10,800	$	10,800	$	10,800
Credit facility borrowings	$	2,569	$	2,569	$	23,311	$	23,311

The estimated fair values of power contract derivatives are based on over-the-counter quotes or broker quotes at the end of the reporting period, with the exception of one long-term power contract that is valued using a binomial tree model and quoted market data when available, along with appropriate valuation methodologies. At June 30, 2010, there were no unrealized losses recorded as liabilities on the Condensed Consolidated Balance Sheet and unrealized gains of $2.8 million were recorded as assets on the Condensed Consolidated Balance Sheet. At December 31, 2009, the fair values were unrealized losses of $0.4 million that were recorded as liabilities on the Consolidated Balance Sheet and unrealized gains of $0.6 million that were recorded as assets on the Consolidated Balance Sheet.

The fair values of our first mortgage bonds are estimated based on quoted market prices for the same or similar issues with similar remaining time to maturity or on current rates offered to us. Fair values are estimated to meet disclosure requirements and do not necessarily represent the amounts at which obligations would be settled.

The table above does not include cash, special deposits, receivables and payables. The carrying values approximate fair value because of the short duration of those instruments. Also, the carrying values of our revenue bonds approximate fair value since the rates are adjusted at least monthly. The carrying value of our credit facility borrowings approximate fair value since the rates can change daily. The fair value of our cash equivalents and restricted cash are included in Note 5 - Fair Value.

NOTE 5 - FAIR VALUE

We recognize certain assets and liabilities at fair value on our Condensed Consolidated Balance Sheets. FASB guidance defines fair value as “the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.”

Valuation Techniques Fair value is not an entity-specific measurement, but a market-based measurement utilizing assumptions market participants would use to price the asset or liability. FASB guidance includes three valuation techniques to be used at initial recognition and subsequent measurement of an asset or liability:

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

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

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

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

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

Level 1: Quoted prices (unadjusted) are available in active markets for identical assets or liabilities as of the reporting date. Level 1 includes cash equivalents that consist of money market funds and directly held securities in our non-qualified Millstone Decommissioning Trust Fund.

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

Level 3: Pricing inputs include significant inputs that are generally less observable. Unobservable inputs may be used to measure the asset or liability where observable inputs are not available. We develop these inputs based on the best information available, including our own data. Level 3 instruments include derivatives related to our forward energy purchases and sales, financial transmission rights and a power-related option contract. There were no changes to our Level 3 fair value measurement methodologies.

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

	Fair Value as of June 30, 2010
	Level 1		Level 2		Level 3		Total
Assets:
Millstone decommissioning trust fund
Investments in securities:
Marketable equity securities	$	1,281	$	2,251	$	0	$	3,532
Marketable debt securities
Corporate bonds				300				300
U.S. Government issued debt securities (Agency and Treasury)				975				975
State and municipal				13				13
Other				22				22
Total marketable debt securities		0		1,310		0		1,310
Cash equivalents and other				47				47
Total investments in securities		1,281		3,608		0		4,889
Cash equivalents		1,262						1,262
Restricted cash								0
Power-related derivatives - current						2,829		2,829
Total assets	$	2,543	$	3,608	$	2,829	$	8,980

Liabilities:
Power-related derivatives - current							$	0
Power-related derivatives - long term								0
Total liabilities	$	0	$	0	$	0	$	0

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	Fair Value as of December 31, 2009
	Level 1		Level 2		Level 3		Total
Assets:
Millstone decommissioning trust fund
Investments in securities:
Marketable equity securities	$	1,382	$	2,427			$	3,809
Marketable debt securities
Corporate bonds				328				328
U.S. Government issued debt securities (Agency and Treasury)				889				889
State and municipal				14				14
Other				4				4
Total marketable debt securities				1,235				1,235
Cash equivalents and other		2		36				38
Total investments in securities		1,384		3,698				5,082
Cash equivalents		746						746
Restricted cash		5,369						5,369
Power-related derivatives - current					$	622		622
Total assets	$	7,499	$	3,698	$	622	$	11,819
Liabilities:
Power-related derivatives - current					$	219	$	219
Power-related derivatives - long term						149		149
Total liabilities	$	0	$	0	$	368	$	368

Millstone Decommissioning Trust Our primary valuation technique to measure the fair value of our nuclear decommissioning trust investments is the market approach. An actively traded quoted price cannot be obtained for the qualified decommissioning fund. However, actively traded quoted prices for the underlying securities comprising the fund have been obtained. Due to these observable inputs, fixed income, equity and cash equivalent securities in the qualified fund are classified as Level 2. Equity securities are held directly in our non-qualified trust and actively traded quoted prices for these securities have been obtained. Due to these observable inputs, these equity securities are classified as Level 1.

We recognize transfers in and out of the fair value hierarchy levels at the end of the reporting period. There were no transfers of equity and debt securities within the fair value hierarchy levels during the period ended June 30, 2010.

Cash Equivalents and Restricted Cash The market approach is used to measure the fair values of money market funds included in cash equivalents and restricted cash. We have the ability to transact our money market funds at the net asset value price per share and can withdraw those funds without a penalty. We are able to obtain actively traded quoted prices for these funds; therefore they are classified as Level 1. Cash equivalents are included in cash and cash equivalents on the Condensed Consolidated Balance Sheets.

Power-related Derivatives We have three types of derivative assets and liabilities: forward energy contracts, Financial Transmission Rights (“FTRs”), and a power-related option contract (“Hydro-Quebec Sellback #3”). Our primary valuation technique to measure the fair value of these derivative assets and liabilities is the income approach, which involves determining a present value amount based on estimated future cash flows. However, when circumstances warrant, we may also use alternative approaches as described below to calculate the fair value for each type of derivative. Since many of the valuation inputs are not observable in the market, we have classified our derivative assets and liabilities as Level 3.

To calculate the fair value of our forward energy contracts, we use a mark-to-market valuation model that includes the following inputs: contract energy prices, forward energy prices, contract volumes and delivery dates, risk-free and credit-adjusted interest rates, counterparty credit ratings and our credit rating.

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To calculate the fair value of our FTR contracts we use two different approaches. For FTR contracts entered into with an auction date close to the reporting date, we use the auction clearing prices obtained from ISO-New England, which represents a market approach to determining fair value. Auction clearing prices are used to value all FTRs at December 31 each year. For FTR contract valuations performed at interim reporting dates, we use an internally developed valuation model to estimate the fair values for the remaining portions of annual FTRs. This model includes the following inputs: historic congestion component prices for the applicable locations, historic energy prices, forward energy prices, contract volumes and durations, and the applicable risk-free rate.

To calculate the fair value of our power-related option contract, we use a binomial tree model which includes the following inputs: forward energy prices, expected volatility, contract volume, prices and duration, and LIBOR swap rates.

Level 3 Reconciliation for Recurring Fair Value Measurements There were no transfers into or out of Level 3 during the periods presented. The following table is a reconciliation of changes in the net fair value of power-related derivatives that are classified as Level 3 in the fair value hierarchy (dollars in thousands).

	Three months ended June 30						Six months ended June 30
	2010			2009			2010			2009
Balance at beginning of period	$	5,586		$	11,292		$	254		$	8,820
Gains and losses (realized and unrealized)
Included in earnings		469			8,805			2,119			13,599
Included in Regulatory and other assets/liabilities		(2,723	)		(7,599	)		2,642			(5,095	)
Purchases, sales, issuances and net settlements		(503	)		(8,839	)		(2,186	)		(13,665	)
Balance as of June 30	$	2,829		$	3,659		$	2,829		$	3,659

During the three and six months ended June 30, 2010 and 2009, there were no realized gains or losses included in earnings attributable to the change in unrealized gains or losses related to derivatives still held at the reporting date. This is due to our regulatory accounting treatment for all power-related derivatives.

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

NOTE 6 - INVESTMENT SECURITIES

Millstone Decommissioning Trust Fund We have decommissioning trust fund investments related to our joint-ownership interest in Millstone Unit #3. The decommissioning trust fund was established pursuant to various federal and state guidelines. Among other requirements, the fund must be managed by an independent and prudent fund manager. Any gains or losses, realized and unrealized, are expected to be refunded to or collected from customers and are recorded as regulatory assets or liabilities in accordance with the FASB guidance for Regulated Operations.

An investment is impaired if the fair value of the investment is less than its cost and if management considers the impairment to be other-than-temporary. We do not have the ability to decide to hold individual equity securities in the trusts because regulatory authorities limit our ability to oversee the day-to-day management of our nuclear decommissioning trust fund investments. Therefore, we consider all equity securities held by our nuclear decommissioning trusts with fair values below their cost basis to be other-than-temporarily impaired. The FASB guidance for Investments - Debt and Equity Securities, requires impairment of debt securities if: 1) there is the intent to sell a debt security; 2) it is more likely than not that the security will be required to be sold prior to recovery; or 3) the entire unamortized cost of the security is not expected to be recovered. For the majority of the investments shown below, we own a share of the trust fund investments.

For the second quarter of 2010, we had nominal realized gains and $0.1 million of realized losses. The realized losses include $0.1 million of impairments associated with our equity securities.

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For the first six months of 2010, we had $0.1 million of realized gains and $0.1 million of realized losses. The realized losses include $0.1 million of impairments associated with our equity securities. Additionally, we recorded a non-credit loss impairment to our debt securities of a nominal amount that is included in unrealized losses. In 2010, there were no permanent impairments or ‘credit losses’ associated with our debt securities.

For the second quarter of 2009, we had $0.1 million of realized gains and less than $0.1 million of realized losses. For the first six months of 2009, we had $0.1 million of realized gains and $0.3 million of realized losses. The realized losses include $0.2 million of impairments associated with our equity securities. In 2009, there were no permanent impairments or ‘credit losses’ associated with our debt securities.

The fair value of these investments is summarized below (dollars in thousands):

	As of June 30, 2010
	Amortized		Unrealized		Unrealized			Estimated
Security Types	Cost		Gains		Losses			Fair Value
Marketable equity securities	$	3,044	$	488	$	0		$	3,532
Marketable debt securities
Corporate bonds		280		21		(1	)		300
U.S. Government issued debt securities (Agency and Treasury)		907		68		0			975
State and municipal		13		0		0			13
Other		22		1		(1	)		22
Total marketable debt securities		1,222		90		(2	)		1,310
Cash equivalents and other		47							47
Total	$	4,313	$	578	$	(2	)	$	4,889

	As of December 31, 2009
	Amortized		Unrealized		Unrealized			Estimated
Security Types	Cost		Gains		Losses			Fair Value
Marketable equity securities	$	3,107	$	702	$	0		$	3,809
Marketable debt securities
Corporate bonds		317		15		(4	)		328
U.S. Government issued debt securities (Agency and Treasury)		850		44		(5	)		889
State and municipal		13		1		0			14
Other		4		0		0			4
Total marketable debt securities		1,184		60		(9	)		1,235
Cash equivalents and other		38		0		0			38
Total	$	4,329	$	762	$	(9	)	$	5,082

Information related to the fair value of debt securities at June 30, 2010 follows (dollars in thousands):

	Fair value of debt securities at contractual maturity dates
	Less than 1 year		1 to 5 years		5 to 10 years		After 10 years		Total
Debt Securities	$	45	$	322	$	288	$	655	$	1,310

At June 30, 2010, the fair value of debt securities in an unrealized loss position was less than $0.1 million. At December 31, 2009, the fair value of debt securities in an unrealized loss position was $0.3 million.

NOTE 7 - RETAIL RATES AND REGULATORY ACCOUNTING

Retail Rates Our retail rates are approved by the PSB after considering the recommendations of Vermont’s consumer advocate, the Vermont Department of Public Service (“DPS”). 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.

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On September 30, 2008, the PSB issued an order approving our alternative regulation plan. The plan became effective on November 1, 2008. It expires on December 31, 2011, but we have petitioned for an extension through December, 2013. The plan allows for quarterly rate adjustments to reflect changes in power supply and transmission-by-others costs (“PCAM” adjustment); annual base rate adjustments to reflect changing costs; and annual rate adjustments to reflect changes, within predetermined limits, from the allowed earnings level (“ESAM” adjustment). Under the plan, the allowed return on equity will be adjusted annually to reflect one-half of the change in the average yield on the 10-year Treasury note as measured over the last 20 trading days prior to October 15 of each year. The ESAM provides for the return on equity of the regulated portion of our business to fall between 75 basis points above or below the allowed return on equity before any adjustment is made. If the actual return on equity of the regulated portion of our business exceeds 75 basis points above the allowed return, the excess amount is returned to customers in a future period. If the actual return on equity of our regulated business falls between 75 and 100 basis points below the allowed return on equity, the shortfall is shared equally between shareholders and customers. Any earnings shortfall in excess of 100 basis points below the allowed return on equity is fully recovered from customers. These adjustments are made at the end of each fiscal year.

On December 31, 2009, the PSB issued its order approving our 2010 base rate filing, which increased rates 5.58 percent, effective for bills rendered beginning January 1, 2010. The allowed rate of return for 2010, calculated in accordance with the plan, is 9.59 percent.

In our 2010 base rate filing, we proposed an amendment to the non-power cost cap formula of our alternative regulation plan to allow for full cost recovery for new initiatives arising after the effective date of the plan. The DPS supported the proposal, and the 2010 base rate filing increase approved by the PSB included recovery of costs for two new initiatives. However, the PSB has not yet acted on the proposed amendment. If the PSB ultimately decides not to approve the amendment, we will be required to refund approximately $0.5 million to customers.

The PCAM adjustment for the second quarter of 2010 was an under-collection of $1 million and was recorded as a current asset. This under-collection will be recovered from customers over the three months ending December 31, 2010. We filed a PCAM report, including supporting documentation, with the PSB identifying this under-collection. The PSB has not yet acted on this filing.

The PCAM adjustment for the first quarter of 2010 was an over-collection of $0.5 million and was recorded as a current liability. We filed a PCAM report, including supporting documentation, with the PSB identifying this over-collection. The DPS recommended the PCAM report be approved as filed and the PSB accepted the DPS recommendation and approved the filing. This over-collection will be returned to customers over the three months ending September 30, 2010.

The PCAM adjustments for 2009 were calculated to be over-collections of $0.6 million in the first quarter, $0.5 million in the second quarter, $0.6 million in the third quarter and $1 million in the fourth quarter. These over-collections were recorded as current liabilities. We filed PCAM reports, including supporting documentation, each quarter with the PSB identifying the over-collections. In each case, the DPS recommended the PCAM report be approved as filed and the PSB accepted the DPS recommendation and approved the filing. The 2009 over-collections were returned to customers over the three months ended September 30, 2009, December 31, 2009, March 31, 2010 and June 30, 2010, respectively.

On May 1, 2010, we filed our 2009 ESAM calculation using the methodology specified in our alternative regulation plan. The 2009 return on equity from the regulated portion of our business was 9.87 percent. No ESAM adjustment was required in 2009 since this return was within 75 basis points of our 2009 allowed return on equity of 9.77 percent.

On June 30, 2010, we filed a required Alternative Regulation Plan Analysis of Plan Performance with the PSB. This analysis evaluated the effectiveness of the Plan’s performance in achieving the goals of Vermont alternative regulation. As described in the evaluation, the implementation of the current plan has helped to advance these goals; however, we also identified concerns and impediments that limit its overall effectiveness in satisfying all of the objectives of Vermont alternative regulation.

To address these concerns, on July 6, 2010 we petitioned the PSB to approve changes to the current plan to: a) extend its duration; b) alter the methodology for implementing the non-power cost cap; and c) reset the allowed return on equity (“ROE”). If these changes are approved, the revised plan will expire on December 31, 2013 and the allowed return on equity will be reset as of January 1, 2011. Thereafter, the existing annual ROE reset methodology would apply for the duration of the plan.

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Staffing Level Investigation On February 13, 2009, the PSB opened an investigation into the staffing levels of the company as requested by us and the DPS.

On November 30, 2009, we filed a Memorandum of Understanding (“Staffing MOU”) with the PSB setting forth agreements that we reached with the DPS regarding the PSB’s investigation into our staffing levels. Under the Staffing MOU, in lieu of retaining a management consultant to perform a comprehensive review of our organizational structure and staffing, we and the DPS have agreed that we will reduce our staffing levels over a five-year period by a total of 17 positions as compared to the 549 positions we had on January 1, 2009. This reduction shall be in addition to the staffing changes contemplated by the implementation of CVPS SmartPower TM . We retain discretion in how to achieve the staffing reductions, and the DPS has agreed that it shall not oppose the recovery in rates of all reasonable costs associated with staffing and related compensation during the term of the Staffing MOU, provided that recovery of such costs is otherwise consistent with normal ratemaking standards. Nothing in the Staffing MOU precludes us from seeking to add staff as reasonably necessary in response to new requirements imposed by the state or federal government.

On March 31, 2010, the PSB approved the Staffing MOU. The Staffing MOU allows CVPS to recover all reasonable costs associated with the staff reductions in accordance with our proposed new initiatives amendment to the non-power cost cap formula of our alternative regulation plan. As discussed above, the PSB has not yet acted on the proposed amendment. If the PSB ultimately decides not to approve the amendment, these costs would become subject to the non-power cost cap. Related costs, if any, are not expected to be material.

CVPS SmartPower TM On October 27, 2009, the DOE announced that Vermont’s electric utilities will receive $69 million in federal stimulus funds to deploy advanced metering, new customer service enhancements and grid automation. As a participant on Vermont’s smart grid stimulus application, we expect to receive a grant of over $31 million. The agreement includes provisions for funding and other requirements.

The agreement was executed on April 15, 2010 and became effective on April 19, 2010. We are eligible to receive reimbursement of 50 percent of our total project cost incurred since August 6, 2009, up to $31 million. Through June 30, 2010, we incurred $1.9 million of costs, of which $1.3 million were operating expenses and $0.6 million were capital expenditures. We submitted a request for reimbursement of 50 percent, or $1 million. We have not yet recorded an accounts receivable on the Condensed Consolidated Balance Sheet, pending initial receipt of the Stimulus funds, which are also subject to subsequent documentation and true-up.

On April 7, 2010, we filed a Memorandum of Understanding (“SmartPower MOU”) with the PSB, which included, among other things, the agreement we reached with the DPS on the recovery of costs we will incur due to CVPS SmartPower TM implementation. We may receive a final regulatory decision by the end of the third quarter 2010.

Our 2010 Base Rate filing included costs that are eligible for government grant reimbursement; however, the grant reimbursement was not reflected in the base rate filing. Grant reimbursement of these 2010 costs will be charged to a regulatory liability and returned to customers in our next base rate filing.

Regulatory Accounting Under FASB’s guidance for regulated operations, we account for certain transactions in accordance with permitted regulatory treatment whereby regulators may permit incurred costs, typically treated as expenses by unregulated entities, to be deferred and expensed in future periods when recovered through future revenues. In the event that we no longer meet the criteria for accounting for regulated operations and there is not a rate mechanism to recover these costs, we would be required to write off $14.1 million of regulatory assets (total regulatory assets of $47.1 million less pension and postretirement medical costs of $33 million), $0.8 million of other deferred charges - regulatory and $5.5 million of other deferred credits - regulatory. This would result in a total charge to operations of $9.4 million on a pre-tax basis as of June 30, 2010. We would be required to record pre-tax pension and postretirement costs of $32.4 million to Accumulated Other Comprehensive Loss and $0.6 million to Retained Earnings as reductions to stockholders’ equity. We would also be required to determine any potential impairment to the carrying costs of deregulated plant. Regulatory assets, certain other deferred charges and other deferred credits are shown in the table below (dollars in thousands).

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	June 30, 2010		December 31, 2009
Regulatory assets
Pension and postretirement medical costs	$	33,011	$	32,033
Nuclear plant dismantling costs		7,815		8,498
Nuclear refueling outage costs - Millstone Unit #3		825		269
Income taxes		4,496		4,389
Asset retirement obligations and other		926		1,051
Total Regulatory assets	$	47,073	$	46,240

Other deferred charges - regulatory
Vermont Yankee sale costs (tax)		673		673
Unrealized losses on power-related derivatives		0		368
Other		176		503
Total Other deferred charges - regulatory	$	849	$	1,544

Other deferred credits - regulatory
Asset retirement obligation - Millstone Unit #3		2,230		2,497
Vermont Yankee settlements		61		183
Unrealized gains on power-related derivatives		2,762		488
Other		457		720
Total Other deferred credits - regulatory	$	5,510	$	3,888

The regulatory assets included in the table above are being recovered in retail rates and are supported by written rate orders. The recovery period for regulatory assets varies based on the nature of the costs. All regulatory assets are earning a return, except for income taxes, nuclear plant dismantling costs, and pension and postretirement medical costs. Other deferred charges – regulatory are supported by PSB-approved accounting orders or approved cost recovery methodologies, allowing cost deferral until recovery in a future rate proceeding. Most items listed in other deferred credits - regulatory are being amortized for periods ranging from two to three years. Pursuant to PSB-approved rate orders, when a regulatory asset or liability is fully amortized, the corresponding rate revenue shall be booked as a reverse amortization in an opposing regulatory liability or asset account.

Regulatory assets for pension and postretirement medical costs are discussed in Note 11 - Pension and Postretirement Medical Benefits. Regulatory assets for nuclear plant dismantling costs are related to our equity interests in Maine Yankee, Connecticut Yankee and Yankee Atomic which are described in Note 3 - Investments in Affiliates. Power-related derivatives are discussed in more detail in Note 5 - Fair Value and Note 10 - Power-related Derivatives.

NOTE 8 - COMMON STOCK

On November 6, 2009, we filed a Registration Statement with the Securities and Exchange Commission (“SEC”) on Form S-3, requesting the ability to offer, from time to time and in one or more offerings, up to $55 million of our common stock. On December 4, 2009, the SEC declared the Registration Statement to be effective. On January 15, 2010, we filed a Prospectus Supplement with the SEC, noting that we entered into an equity distribution agreement that allowed us to issue up to $45 million of shares under an “at-the-market” program. As of June 30, 2010, 582,831 shares of our common stock have been issued, yielding net proceeds of $11.8 million.

NOTE 9 - LONG-TERM DEBT AND CREDIT FACILITY

Credit Facility: We have a three-year, $40 million unsecured revolving credit facility with a lending institution pursuant to a Credit Agreement dated November 3, 2008. It contains financial and non-financial covenants. Our obligation under the Credit Agreement is guaranteed by our wholly owned, unregulated subsidiaries, C.V. Realty and CRC. The purpose of the facility is to provide liquidity for general corporate purposes, including working capital and power contract performance assurance requirements, in the form of funds borrowed and letters of credit. At June 30, 2010, $2.6 million in loans and $5.5 million in letters of credit were outstanding under this credit facility.

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We also have a 364-day, $15 million unsecured revolving credit facility with a different lending institution pursuant to a credit agreement dated December 30, 2009. The purpose of and our obligation under this credit agreement are the same as described above. At June 30, 2010, there were no borrowings or letters of credit outstanding under this credit facility.

Current Portion of long-term debt: In June 2010, we reclassified $20 million of long-term debt to current portion of long-term debt on the Condensed Consolidated Balance Sheet. Our First Mortgage Bonds, Series SS are due in June 2011.

Covenants: Our long-term debt indentures, letters of credit, credit facilities and articles of association contain financial covenants. The most restrictive financial covenants include maximum debt to total capitalization of 65 percent, and minimum mortgage bond interest coverage of 2.0 times. At June 30, 2010, we were in compliance with all financial covenants related to our various debt agreements, articles of association, letters of credit, credit facilities and material agreements.

NOTE 10 - POWER-RELATED DERIVATIVES

We are exposed to certain risks in managing our power supply resources to serve our customers, and we use derivative financial instruments to manage those risks. The primary risk managed by using derivative financial instruments is commodity price risk. Currently, our power supply forecast shows energy purchase and production amounts in excess of our load requirements through 2011. Because of this projected power surplus, we entered into a 2010 forward power sale contract to reduce the price volatility of our net power costs. Deliveries under this sale contract are excused during any period of time that Vermont Yankee is not operating as a result of an unplanned outage. On occasion, we will forecast a temporary power supply shortage such as when Vermont Yankee becomes unavailable. We typically enter into short-term forward power purchase contracts to cover a portion of these expected power supply shortages, which helps to reduce price volatility in our net power costs. Our power supply forecast shows that in 2012, our load requirements will exceed our energy purchase and production amounts, as certain committed long-term power purchase contracts begin to expire.

Several years ago, we entered into the Hydro-Quebec Sellback #3 contract, a long-term purchased power contract that allows the seller to repurchase specified amounts of power with advance notice. The option under this contract will expire by the end of 2010. In addition, we are able to economically hedge our exposure to congestion charges that result from constraints on the transmission system with FTRs. FTRs are awarded to the successful bidders in periodic auctions administered by ISO-New England. We do not use derivative financial instruments for trading or other purposes.

Accounting for power-related derivatives is discussed in Note 1- Business Organization and Summary of Significant Accounting Policies - Derivative Financial Instruments.

As of June 30, 2010, we had the following outstanding power-related derivative contracts:

Commodity	mWh (000s)
Forward Energy Contracts	293.6
Financial Transmission Rights	1,043.9
Hydro-Quebec Sellback #3	136.9

We recognized the following amounts in the Condensed Consolidated Statements of Income in connection with derivative financial instruments (dollars in thousands):

	Three months ended June 30						Six months ended June 30
	2010			2009			2010			2009
Net realized gains (losses) reported in operating revenues	$	1,028		$	8,845		$	2,700		$	13,657
Net realized gains (losses) reported in purchased power	$	(559	)	$	(40	)	$	(581	)	$	(58	)

Realized gains and losses on derivative instruments are conveyed to or recovered from customers through the PCAM and have no impact on results of operations. Derivative transactions and related collateral requirements are included in net cash flows from operating activities in the Condensed Consolidated Statements of Cash Flows. For information on the location and amounts of derivative fair values on the Condensed Consolidated Balance Sheets see Note 5 - Fair Value.

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Certain of our power-related derivative instruments contain provisions for performance assurance that may include the posting of collateral in the form of cash or letters of credit, or other credit enhancements. Our counterparties will typically establish collateral thresholds that represent credit limits, and these credit limits vary depending on our credit rating. If our current credit rating were to decline, certain counterparties could request immediate payment and full overnight ongoing collateralization on derivative instruments in net liability positions. We have no derivative instruments with credit-risk related contingent features that were in a liability position on June 30, 2010. For information concerning performance assurance, see Note 12 - Commitments and Contingencies - Performance Assurance.

NOTE 11 - PENSION AND POSTRETIREMENT MEDICAL BENEFITS

The fair value of Pension Plan trust assets was $94.6 million at June 30, 2010 and $97.2 million at December 31, 2009. The unfunded accrued pension benefit obligation recorded on the Condensed Consolidated Balance Sheets was $21.2 million at June 30, 2010 and $19.8 million at December 31, 2009.

The fair value of Postretirement Plan trust assets was $14.8 million at June 30, 2010 and $15 million at December 31, 2009. The unfunded accrued postretirement benefit obligation recorded on the Condensed Consolidated Balance Sheets was $14.5 million at June 30, 2010, and $13.8 million at December 31, 2009.

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

Pension Benefits	Three months ended June 30						Six months ended June 30
	2010			2009			2010			2009
Service cost	$	1,026		$	946		$	2,052		$	1,892
Interest cost		1,754			1,652			3,508			3,304
Expected return on plan assets		(2,063	)		(2,077	)		(4,126	)		(4,154	)
Amortization of net actuarial loss		0			86			0			172
Amortization of prior service cost		107			0			214			0
Net periodic benefit cost		824			607			1,648			1,214
Less amount allocated to other accounts		229			72			318			140
Net benefit costs expensed	$	595		$	535		$	1,330		$	1,074

Postretirement Benefits	Three months ended June 30						Six months ended June 30
	2010			2009			2010			2009
Service cost	$	228		$	178		$	456		$	356
Interest cost		395			428			790			856
Expected return on plan assets		(301	)		(196	)		(602	)		(392	)
Amortization of net actuarial loss		242			70			484			140
Amortization of transition (asset) obligation		64			379			128			758
Amortization of prior service cost		70			64			140			128
Net periodic benefit cost		698			923			1,396			1,846
Less amounts capitalized		193			110			269			212
Net benefit costs expensed	$	505		$	813		$	1,127		$	1,634

Investment Strategy Our pension investment policy seeks to achieve sufficient growth to enable the Pension Plan to meet our future benefit obligations to participants, maintain certain funded ratios and minimize near-term cost volatility. Current guidelines specify generally that 54 percent of plan assets be invested in equity securities and 46 percent of plan assets be invested in debt securities. The debt securities are comprised of long-duration bonds to match changes in plan liabilities.

Our postretirement medical benefit plan investment policy seeks to achieve sufficient funding levels to meet future benefit obligations to participants and minimize near-term cost volatility. Current guidelines specify generally that 60 percent of the plan assets be invested in equity securities and 40 percent be invested in debt securities. Fixed-income securities are of a shorter duration to better match the cash flows of the postretirement medical obligation.

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Health Care Legislation On March 23, 2010, the federal Patient Protection and Affordable Care Act (“the Act”) was signed into law. The Act is a comprehensive health care reform bill that includes revenue-raising provisions for nearly $400 billion over 10 years through tax increases on high-income individuals, excise taxes on high-cost group health plans, and new fees on selected health-care-related industries. In addition, on March 25, 2010, the Health Care and Education Affordability Reconciliation Act of 2010 was passed into law, which modifies certain provisions of the Act.

Together, the legislation repeals the current rule permitting a tax deduction for prescription drug coverage expense under our postretirement medical plan that is actuarially equivalent to that provided under Medicare Part D. This provision is effective for taxable years beginning after December 31, 2012. As required, in March 2010 we recorded an increase of $2.1 million in regulatory assets and an increase of $2.8 million in deferred income taxes on the Condensed Consolidated Balance Sheets, resulting in an increase of $0.7 million in income tax expense on the Condensed Consolidated Statements of Income, related to postretirement medical expenditures that will not be deductible in the future.

Trust Fund Contributions In July 2010, we contributed $2.7 million to the pension trust fund and $3.3 million to the postretirement medical trust funds. We do not plan to make any additional contributions to these trust funds in 2010. In June 2009, we contributed $2.4 million to the pension trust fund and $3.8 million to the postretirement medical trust funds.

NOTE 12 - COMMITMENTS AND CONTINGENCIES

Long-Term Power Purchases Vermont Yankee: We are purchasing our entitlement share of Vermont Yankee plant output through a purchased power contract (“PPA”) between Entergy-Vermont Yankee and VYNPC. VYNPC’s entitlement to plant output is 83 percent and our share of plant output is 29 percent; our nominal entitlement is approximately 180 MW. We have one secondary purchaser that receives less than 0.5 percent of our entitlement.

Entergy-Vermont Yankee has no obligation to supply energy to VYNPC over its entitlement share of plant output, so we receive reduced amounts when the plant is operating at a reduced level, and no energy when the plant is not operating. The plant normally shuts down for about one month every 18 months for maintenance and to insert new fuel into the reactor. A refueling outage was completed in May 2010 and estimated incremental costs for replacement power were factored into our 2010 base rates.

Our total VYNPC purchases were $10.2 million in the second quarter and $26.4 million in the first six months of 2010 and $15.7 million in the second quarter and $31.4 million in the first six months of 2009.

We have a forced outage insurance policy to cover additional costs, if any, of obtaining replacement power from other sources if the Vermont Yankee plant experiences unplanned outages. The current policy covers March 22, 2010 through March 21, 2011. This outage insurance does not apply to derates or acts of terrorism. The coverage applies to unplanned outages of up to 90 consecutive calendar days per outage event, and provides for payment of the difference between the hourly spot market price and $42/mWh. The aggregate maximum coverage is $9 million with a $1.2 million deductible.

In the third quarter of 2007, the Vermont Yankee plant experienced a derate after the collapse of a cooling tower at the plant, and a two-day unplanned outage resulting from a valve failure. The derate and unplanned outage increased our net power costs by about $1.3 million through increased purchased power expense and decreased operating revenues due to reduced resale sales. We were also able to apply $0.3 million as a reduction in purchased power expense from the regulatory liability.

We are considering whether to seek recovery of the incremental costs from Entergy-Vermont Yankee under the terms of the PPA based upon the results of certain reports, including an NRC inspection, in which the inspection team found that Entergy-Vermont Yankee, among other things, did not have sufficient design documentation available to help it prevent problems with the cooling towers. The NRC released its findings on October 14, 2008. In considering whether to seek recovery, we are also reviewing the 2007 and 2008 root cause analysis reports by Entergy and a December 22, 2008 reliability assessment provided by the Nuclear Safety Associates to the State of Vermont. We cannot predict the outcome of this matter at this time.

The PPA between Entergy-Vermont Yankee and VYNPC contains a formula for determining the VYNPC power entitlement following an uprate in 2006 that increased the plant’s operating capacity by approximately 20 percent. VYNPC and Entergy-Vermont Yankee are seeking to resolve certain differences in the interpretation of the formula. At issue is how much capacity and energy VYNPC Sponsors receive under the PPA following the uprate. Based on VYNPC’s calculations the VYNPC Sponsors should be entitled to slightly more capacity and energy than they are currently receiving under the PPA. We cannot predict the outcome of this matter at this time.

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Our contract for power purchases from VYNPC ends in March 2012, but there is a risk that we could lose this resource if the plant shuts down for any reason before that date. An early shutdown could cause our customers to lose the economic benefit of an energy volume of close to 50 percent of our total committed supply and we would have to acquire replacement power resources for approximately 40 percent of our estimated power supply needs. Based on forward market prices as of June 30, 2010, the incremental replacement cost of lost power is estimated to average $17 million annually over the remaining life of the contract. We are not able to predict whether there will be an early shutdown of the Vermont Yankee plant or whether the PSB would allow timely and full recovery of increased costs related to such shutdown. An early shutdown, depending upon the specific circumstances, could involve cost recovery via the outage insurance described above and recoveries under the PCAM but, in general, would not be expected to materially impact financial results if the costs are recovered in retail rates in a timely fashion.

Entergy-Vermont Yankee has submitted a renewal application with the NRC and an application for a Certificate of Public Good (“CPG”) with the PSB for a 20-year extension of the Vermont Yankee plant operating license. Entergy-Vermont Yankee also needs approval from the PSB and Vermont Legislature to continue to operate beyond 2012. Significant hurdles may prevent its relicensing. Potential operating, transparency and communication issues related to the plant have raised serious concerns among regulators and members of the Vermont Legislature, including some who have called for its temporary or permanent shutdown. An intervenor in the CPG case has requested that the PSB order a shutdown of the Vermont Yankee plant due to recent leaks at the site. The PSB has opened a new docket to consider that request. We are unable to predict the outcome of this matter.

On February 24, 2010, in a non-binding vote, the Vermont Senate voted against allowing the PSB to consider granting the Vermont Yankee plant another 20-year operating license after 2012. A new Vermont legislature will be elected in the fall of 2010 and could vote differently. We are unable to predict the outcome of this matter.

Entergy-Vermont Yankee is attempting to overcome these concerns, and in April 2010, we began a new round of negotiations on a new contract. We rejected Entergy-Vermont Yankee’s last public proposal, but both parties continue to exchange information and proposals. The parties are attempting to negotiate a purchased power contract in order that the state will have the value of such an agreement to consider should the other 20-year extension issues that have emerged be resolved. We cannot predict the outcome of this matter at this time.

Hydro-Quebec: We are purchasing power from Hydro-Quebec under the Vermont Joint Owners (“VJO”) Power Contract. The VJO Power Contract has been in place since 1987 and purchases began in 1990. Related contracts were subsequently negotiated between us and Hydro-Quebec, altering the terms and conditions contained in the original contract by reducing the overall power requirements and related costs. The VJO contract runs through 2020, but our purchases under the contract end in 2016. The average level of deliveries decreases by approximately 19 percent after 2012, and by approximately 84 percent after 2015. Our total purchases under the VJO contract were $15.1 million in the second quarter and $31.7 million in the first six months of 2010 and $15.2 million in the second quarter and $32.2 million in the first six months of 2009.

The annual load factor is 75 percent for the remainder of the VJO Power Contract, unless the contract is changed or there is a reduction due to the adverse hydraulic conditions described below.

There are two sellback contracts with provisions that apply to existing and future VJO Power Contract purchases. The first resulted in the sellback of 25 MW of capacity and associated energy through April 30, 2012, which has no net impact currently since an identical 25 MW purchase was made in conjunction with the sellback. We have a 23 MW share of the 25 MW sellback. However, since the sellback ends six months before the corresponding purchase ends, the first sellback will result in a 23 MW increase in our capacity and energy purchases for the period from May 1, 2012 through October 1, 2012.

A second sellback contract provided benefits to us that ended in 1996 in exchange for two options to Hydro-Quebec. The first option gives Hydro-Quebec the right, upon four years’ written notice, to reduce capacity and associated energy deliveries by 50 MW, including the use of a like amount of our Phase I/II transmission facility rights. The second gives Hydro-Quebec the right, upon one year’s written notice, to curtail energy deliveries in a contract year (12 months beginning November 1) from an annual capacity factor of 75 to 50 percent due to adverse hydraulic conditions as measured at certain metering stations on unregulated rivers in Quebec. This second option can be exercised five times through October 2015. To date, Hydro-Quebec has not exercised these options. We have determined that the first option is a derivative, but the second is not because it is contingent upon a physical variable.

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There are specific contractual provisions providing that in the event any VJO member fails to meet its obligation under the contract with Hydro-Quebec, the remaining VJO participants will “step-up” to the defaulting party’s share on a pro-rata basis. As of June 30, 2010, our obligation is about 47 percent of the total VJO Power Contract through 2016, and represents approximately $320.3 million, on a nominal basis.

In accordance with FASB’s guidance for guarantees, we are required to disclose the “maximum potential amount of future payments (undiscounted) the guarantor could be required to make under the guarantee.” Such disclosure is required even if the likelihood is remote. With regard to the “step-up” provision in the VJO Power Contract, we must assume that all members of the VJO simultaneously default in order to estimate the “maximum potential” amount of future payments. We believe this is a highly unlikely scenario given that the majority of VJO members are regulated utilities with regulated cost recovery. Each VJO participant has received regulatory approval to recover the cost of this purchased power contract in its most recent rate applications. Despite the remote chance that such an event could occur, we estimate that our undiscounted purchase obligation would be an additional $375.4 million for the remainder of the contract, assuming that all members of the VJO defaulted by July 1, 2010 and remained in default for the duration of the contract. In such a scenario, we would then own the power and could seek to recover our costs from the defaulting members or our retail customers, or resell the power in the wholesale power markets in New England. The range of outcomes (full cost recovery, potential loss or potential profit) would be highly dependent on Vermont regulation and wholesale market prices at the time.

Hydro-Quebec Preliminary Agreement: On March 11, 2010, we signed a preliminary agreement (“the agreement”) with Green Mountain Power and Hydro-Quebec (“parties”) that sets the stage for a new power supply contract. Under the terms of the agreement, Vermont utilities will be eligible to purchase up to 225 megawatts beginning in November 2012 and ending in 2038. We will seek to purchase volumes similar to what we currently purchase from Hydro-Quebec. The preliminary agreement includes a price-smoothing mechanism that will shield customers from volatile market price spikes over the life of the contract.

The agreement committed the parties to negotiate in good faith a power purchase agreement based on a non-binding term sheet. The parties intend to obtain all necessary internal organizational approvals and execute the agreement in early August 2010. The final agreement will be subject to PSB approval.

Independent Power Producers: We receive power from several Independent Power Producers (“IPPs”). These plants use water or biomass as fuel. Most of the power comes through a state-appointed purchasing agent that allocates power to all Vermont utilities under PSB rules. Our total purchases from IPPs were $5.8 million in the second quarter and $12.2 million in the first six months of 2010 and $5.8 million in the second quarter of 2009 and $11.7 million in the first six months of 2009.

Nuclear Decommissioning Obligations We are obligated to pay our share of nuclear decommissioning costs for nuclear plants in which we have an ownership interest. We have an external trust dedicated to funding our joint-ownership share of future decommissioning costs. Dominion Nuclear Connecticut (“DNC”) has suspended contributions to the Millstone Unit #3 Trust Fund because the minimum NRC funding requirements have been met or exceeded. We have also suspended contributions to the Trust Fund, but could choose to renew funding at our own discretion as long as the minimum requirement is met or exceeded. If a need for additional decommissioning funding is necessary, we will be obligated to resume contributions to the Trust Fund.

We have equity ownership interests in Maine Yankee, Connecticut Yankee and Yankee Atomic. These plants are permanently shut down and completely decommissioned except for the spent fuel storage at each location. Our obligations related to these plants are described in Note 3 - Investments in Affiliates.

We also had a 35 percent ownership interest in the Vermont Yankee nuclear power plant through our equity investment in VYNPC, but the plant was sold in 2002. Our obligation for plant decommissioning costs ended when the plant was sold, except that VYNPC retained responsibility for the pre-1983 spent fuel disposal cost liability. VYNPC has a dedicated Trust Fund that meets most of the liability. Changes in the underlying interest rates that affect the earnings and the liability could cause the balance to be a surplus or deficit. Excess funds, if any, will be returned to us and the other former owners and must be applied to the benefit of retail customers.

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DOE Litigation We have a 1.7303 joint-ownership percentage in Millstone Unit #3, in which Dominion Nuclear Connecticut (“DNC”) is the lead owner with 93.4707 percent of the plant joint-ownership. In January 2004 DNC filed, on behalf of itself and the two minority owners, including us, a lawsuit against the DOE seeking recovery of costs related to the 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 commenced in May 2008. On October 15, 2008, the United States Court of Federal Claims issued a favorable decision in the case, including damages specific to Millstone Unit #3. The DOE appealed the court’s decision in December 2008. On February 20, 2009, the government filed a motion seeking an indefinite stay of the briefing schedule. On March 18, 2009, the court granted the government’s request to stay the appeal. On November 19, 2009, DNC filed a motion to lift the stay. On April 12, 2010, the stay was lifted and a staggered briefing schedule was proposed, to which DNC has responded with a request to expedite the briefing schedule so that the appeals of all parties be heard concurrently.

On June 30, 2010, the DOE filed its initial brief in the spent fuel damages litigation. This brief focuses on the costs awarded in connection with Millstone Unit #3. DNC’s response to the government’s brief is due on or about August 12, 2010. The government’s reply brief, assuming no extensions, is due August 30, 2010, after which briefing on the appeal will be complete. It is expected that the court will schedule oral argument thereafter, with a decision on the appeal to follow.

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.

Performance Assurance We are subject to performance assurance requirements through ISO-New England under the Financial Assurance Policy for NEPOOL members. At our current investment-grade credit rating, we have a credit limit of $2.8 million with ISO-New England. We are required to post collateral for all net purchased power transactions in excess of this credit limit. 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.

At June 30, 2010, we had posted $6 million of collateral under performance assurance requirements for certain of our power contracts, of which $5.5 million was in the form of a letter of credit and $0.5 million was represented by cash and cash equivalents. At December 31, 2009, we had posted $5.4 million of collateral under performance assurance requirements for certain of our power contracts, all of which was represented by restricted cash.

We are also subject to performance assurance requirements under our Vermont Yankee power purchase contract (the 2001 Amendatory Agreement). If Entergy-Vermont Yankee, the seller, has commercially reasonable grounds to question our ability to pay for our monthly power purchases, Entergy-Vermont Yankee 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.

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

The total reserve for environmental matters was $1.5 million as of June 30, 2010 and $1.6 million as of December 31, 2009. The reserve for environmental matters is included as current and long-term liabilities on the Condensed Consolidated Balance Sheets and represents our best estimate of the cost to remedy issues at these sites based on available information as of the end of the applicable reporting periods. Below is a brief discussion of the significant sites for which we have recorded reserves.

Cleveland Avenue Property : The Cleveland Avenue property in Rutland, Vermont, was used by a predecessor to make gas from coal. Later, we sited various operations there. Due to the existence of coal tar deposits, polychlorinated biphenyl (“PCB”) contamination and the potential for off-site migration, we conducted studies in the late 1980s and early 1990s to quantify the potential costs to remediate the site. Investigation at the site has continued, including work with the State of Vermont to develop a mutually acceptable solution. In June 2010 both the Vermont Agency of Natural Resources (“VT ANR”) and the EPA approved separate remediation work plans for the manufactured gas plant and PCB waste at the site. We are seeking bids for PCB remedial work and we expect that work to start in August 2010. We have reviewed our reserve for this site based on a 2006 cost estimate of remediation and determined that it is adequate. The liability for site remediation is expected to range from $0.9 million to $2.3 million. As of June 30, 2010, we have accrued $0.9 million representing the most likely remaining cost of the remediation effort.

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Brattleboro Manufactured Gas Facility : In the 1940s, we owned and operated a manufactured gas facility in Brattleboro, Vermont. We ordered a site assessment in 1999 at the request of the State of New Hampshire. In 2001, New Hampshire indicated that no further action was required, though it reserved the right to require further investigation or remedial measures. In 2002, the Vermont Agency of Natural Resources notified us that our corrective action plan for the site was approved. That plan is now in place. We have reviewed our reserve for this site based on a 2006 cost estimate of remediation and determined that it is adequate. The liability for site remediation is expected to range from $0.1 million to $1.3 million. As of June 30, 2010, we have accrued $0.5 million representing the most likely remaining cost of the remediation effort.

Currently, the Windham Regional Commission and the Town of Brattleboro are pursuing the redevelopment of the gas plant site and waterfront area into vehicle parking with green space. This concept calls for the removal of the remnant gas plant building plus covering and otherwise avoiding contaminated areas instead of removing contaminated soil and debris. We are assessing the cost implications of this conceptual plan. Currently we do not believe the impact of the plan will be material.

Dover, New Hampshire, Manufactured Gas Facility: In 1999, Public Service Company of New Hampshire (“PSNH”) contacted us about this site. PSNH alleged that we were partially liable for cleanup, since the site was previously operated by Twin State Gas and Electric, which merged into CVPS on the same day that PSNH bought the facility. In 2002, we reached a settlement with PSNH in which certain liabilities we might have had were assigned to PSNH in return for a cash settlement we paid based on completion of PSNH’s cleanup effort. As of June 30, 2010, our remaining obligation was less than $0.1 million.

Other: In December 2009, we voluntarily submitted results of internally tested soil samples from two additional locations to the State of Vermont Sites Management Section (“SMS”). These soil sample results showed contamination at levels of concern to SMS. As a result, SMS listed these sites as active hazardous waste sites and requested that we complete additional testing at these properties. Although management does not believe there is significant contamination at these sites, the extent and cost of potential remediation will not be known until the additional testing is completed during 2010.

To management’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 us for any other study or remediation.

Catamount Indemnifications On December 20, 2005, we completed the sale of Catamount, our wholly owned subsidiary, to CEC Wind Acquisition, LLC, a company established by Diamond Castle Holdings, a New York-based private equity investment firm (“Diamond Castle”). Under the terms of the agreements with Catamount and Diamond Castle, we 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 ended June 30, 2007, except certain items that customarily survive indefinitely. Indemnification is subject to a $1.5 million deductible and a $15 million cap, excluding certain customary items. Environmental representations are subject to the deductible and the cap, and such environmental representations for only two of Catamount’s underlying energy projects survived beyond June 30, 2007. Our estimated “maximum potential” amount of future payments related to these indemnifications is limited to $15 million. We have not recorded any liability related to these indemnifications.

Leases and support agreements

Operating Leases: We have two master lease agreements for vehicles and related equipment. On October 30, 2009, we signed a vehicle lease agreement to finance many of the vehicles covered by a former agreement. Our guarantee obligation under this lease will not exceed 8 percent of the acquisition cost. The maximum amount of future payments under this guarantee at June 30, 2010 is approximately $0.4 million. The total future minimum lease payments required for all lease schedules under this agreement at June 30, 2010 is $4.3 million. The maximum amount approved for lease under this agreement is $5.5 million, of which $5.3 million was outstanding at June 30, 2010.

On October 24, 2008, we entered into an operating lease for new vehicles and other related equipment. Our guarantee obligation under this lease is limited to 5 percent of the acquisition cost. The maximum amount of future payments under this guarantee is approximately $0.1 million. The total future minimum lease payments required for all lease schedules under this agreement at June 30, 2010 is $2.4 million. The total acquisition cost of all lease additions under this agreement at June 30, 2010 is $2.9 million. The maximum amount available for lease additions in 2010 under this agreement is $4 million, of which $0.3 million has been added at June 30, 2010.

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Customer Bankruptcy On October 26, 2009, a major telecommunications customer filed for bankruptcy protection. As of June 30, 2010, our accounts receivable includes an estimate of the net realizable amount. In May 2010, a settlement agreement was reached; however, it is subject to court approval. On June 28, 2010, the PSB rejected the bankruptcy plan; therefore, this could delay the court’s approval of the plan and final settlement. We are unable to predict the outcome of this matter, or its impact on our financial statements, at this time.

Legal Proceedings We are involved in legal and administrative proceedings in the normal course of business. We do not believe that the ultimate outcome of these proceedings will have a material adverse effect on our financial position, results of operations or cash flows.

NOTE 13 - PENDING ACQUISITIONS

On April 30, 2010, we signed a purchase and sale agreement with Omya, Inc. to purchase certain generating, transmission and distribution assets located in the State of Vermont. Under this agreement, we will pay $33.2 million for the transmission and distribution assets and generating assets comprised of four hydroelectric generating stations. The agreement contains usual and customary purchase and sale terms and conditions and is contingent upon federal and state regulatory approvals. The transaction is currently scheduled to close in the fourth quarter of 2010.

NOTE 14 - SEGMENT REPORTING

The following table provides segment financial data for the three and six months ended June 30 (dollars in thousands). Inter-segment revenues were a nominal amount in all periods presented.

					Reclassification &
			Other		Consolidating
	CV VT		Companies		Entries			Consolidated
Three Months Ended
June 30, 2010
Revenues from external customers	$	79,937	$	435	$	(435	)	$	79,937
Net income	$	1,386	$	59	$	0		$	1,445
Total assets at June 30	$	620,821	$	2,509	$	(246	)	$	623,084

June 30, 2009
Revenues from external customers	$	82,627	$	433	$	(433	)	$	82,627
Net income	$	5,439	$	58	$	0		$	5,497
Total assets at December 31	$	630,103	$	2,356	$	(307	)	$	632,152

Six Months Ended
June 30, 2010
Revenues from external customers	$	170,944	$	868	$	(868	)	$	170,944
Net income	$	5,535	$	112	$	0		$	5,647
Total assets at June 30	$	620,821	$	2,509	$	(246	)	$	623,084

June 30, 2009
Revenues from external customers	$	173,354	$	852	$	(852	)	$	173,354
Net income	$	12,256	$	113	$	0		$	12,369
Total assets at December 31	$	630,103	$	2,356	$	(307	)	$	632,152

NOTE 15 - SUBSEQUENT EVENTS

We consider events or transactions that occur after the balance sheet date, but before the financial statements are issued, to provide additional evidence relative to certain estimates or to identify matters that require additional disclosure.

We have reviewed subsequent events and concluded that no material subsequent events have occurred that are not accounted for in the accompanying financial statements or disclosed in the accompanying notes.

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

In this section we discuss our general financial condition and results of operations. Certain factors that may impact future operations are also discussed. Our discussion and analysis are based on, and should be read in conjunction with, the accompanying Condensed Consolidated Financial Statements. The discussion below also includes non-U.S. GAAP measures referencing earnings per diluted share for variances described below in Results of Operations. We use this measure to provide additional information and believe that this measurement is useful to investors to evaluate the actual performance and contribution of our business activities. This non-U.S. GAAP measure should not be considered as an alternative to our consolidated fully diluted earnings per share determined in accordance with U.S. GAAP as an indicator of our operating performance.

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,” “may”, “will”, “should”, “project”, “plan”, “seek”, “intend” or similar expressions or the negative thereof are intended to identify such forward-looking statements. Forward-looking statements involve estimates, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Actual results will depend upon, among other things:

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

We cannot predict the outcome of any of these matters; accordingly, there can be no assurance as to actual results. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise. A more detailed assessment of the risks that could cause actual results to materially differ from current expectations is contained in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2009.

EXECUTIVE SUMMARY

Our core business is the Vermont electric utility business. The rates we charge for retail electricity sales are regulated by the PSB. Fair regulatory treatment is fundamental to maintaining our financial stability. Rates must be set at levels to recover costs, including a market rate of return to equity and debt holders, in order to attract capital. As discussed under the heading Retail Rates and Alternative Regulation below, the PSB approved the alternative regulation plan that we proposed in August 2007, with modifications. This plan provides more timely adjustments to power, operating and maintenance costs, which better serves the interests of customers and shareholders.

Our consolidated earnings for the second quarter of 2010 were $1.4 million, or 11 cents per diluted share of common stock, and $5.6 million, or 46 cents per diluted share of common stock, for the first six months. This compares to consolidated earnings of $5.5 million, or 46 cents per diluted share of common stock for the second quarter, and $12.4 million, or $1.04 per diluted share of common stock, for the first six months of 2009. The primary drivers of the second quarter year-over-year earnings variance are described in Results of Operations below.

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Major Storm: A major winter storm knocked out power to more than 91,000 of our retail customers throughout our service territory in February 2010. The cost of this storm is $3.1 million, making it one of the five most-expensive storms in our history. In May 2010, a second major storm resulted in service restoration costs of $1.2 million. Our rates include a five-year average of storm restoration costs, but given the magnitude of these major storms, that average will not fully recover our current costs. Any incremental service restoration costs above the level currently reflected in our retail rates may be deferred at year-end for recovery through the earnings sharing adjustment mechanism (“ESAM” adjustment) and exogenous effects provisions of our alternative regulation plan.

Health Care Legislation In March 2010, the federal Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act of 2010 were passed into law. Together, the legislation required us to record $0.7 million of additional income tax expense related to postretirement medical costs. Also, see Recent Accounting Pronouncements below for additional information.

Financial Initiatives: Our financial initiatives include maintaining sufficient liquidity to support ongoing operations, the dividend on our common stock and investments in our electric utility infrastructure; planning for replacement power when our long-term power contracts expire; and evaluating opportunities to further invest in Transco. Continued focus on these financial initiatives is critical to maintaining our corporate credit rating.

We discuss these financial initiatives and the risks facing our business in more detail below.

RETAIL RATES AND ALTERNATIVE REGULATION

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Staffing Level Investigation On February 13, 2009, the PSB opened an investigation into the staffing levels of the company as requested by us and the DPS.

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LIQUIDITY, CAPITAL RESOURCES AND COMMITMENTS

Cash Flows At June 30, 2010, we had cash and cash equivalents of $2.6 million compared to $8.9 million at June 30, 2009. The primary components of cash flows from operating, investing, and financing activities for both periods are discussed in more detail below.

Our primary sources of cash in 2010 were from our electric utility operations, proceeds from our revolving credit facility, proceeds from the issuance of common stock, refunds of income taxes and distributions received from affiliates. Our primary uses of cash in 2010 included capital expenditures for utility operations, utility operating expenses, common and preferred dividend payments, repayments of borrowings under our revolving credit facility and interest expense.

Operating Activities: Operating activities provided $27.2 million in the first six months of 2010, compared to $20.5 million in the same period of 2009. The increase of $6.7 million was due to a number of items. The $6.4 million favorable variance in cash requirements for power collateral is mostly resulting from replacing purchased power cash collateral with a letter of credit and the increase of $6.7 million related to employee benefit plan funding is mostly due to the timing of $6 million of annual trust fund payments made in July 2010 vs. $6.2 million of annual trust fund payments made in June 2009. In the first six months of 2010, we received net income tax refunds of $5.6 million compared to net income tax refunds of $3.3 million in the first six months of 2009. Tax refunds during both years primarily related to our elections for federal bonus depreciation. These items were primarily offset by a decrease of $6.6 million in resale sales in the first six months as a result of reduced contract rates for resale power sales, a decrease of $4.3 million from increased major storm costs and a decrease of $3 million resulting from planned outages at the Vermont Yankee and Millstone Unit #3 nuclear plants.

Our accounts receivable over 60 days from retail customers was $2.4 million at June 30, 2010 and $2.5 million at December 31, 2009, a decrease of 3 percent.

Investing Activities: Investing activities used $12.3 million in the first six months of 2010 compared to $13.2 million in the same period of 2009, and there were no significant variances among the uses year over year. The majority of the construction and plant expenditures were for system reliability, performance improvements and customer service enhancements.

Financing Activities: Financing activities used $14.3 million in the first six months of 2010, compared to $5.1 million in the same period of 2009. The decrease of $9.2 million was primarily due to $20.7 million of higher net repayments of borrowings under our revolving credit facility in 2010, partially offset by $11.8 million of net proceeds from our at-the-market common stock issuance program through June 30, 2010.

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Transco Based on current projections, Transco expects to need additional equity capital from 2010 through 2012, but its projections are subject to change based on a number of factors, including revised construction estimates, timing of project approvals from regulators, and desired changes in its equity-to-debt ratio. While we have no obligation to make additional investments in Transco, which are subject to available capital and appropriate regulatory approvals, we continue to evaluate investment opportunities on a case-by-case basis. We could have an opportunity to make additional investments of up to $41.2 million in 2010, $11.1 million in 2011, $44.4 million in 2012 and $57.7 million in 2013, but the timing and amounts depend on the factors discussed above and the amounts invested by other owners.

We are currently evaluating debt and equity issuance alternatives to fund these investments, but any investments that we make in Transco are voluntary, and subject to available capital and appropriate regulatory approvals. These capital investments in Transco and our core business provide value to customers and shareholders alike. They provide shareholders with a return on investment while helping to maintain and improve reliability for our customers.

Pending Acquisitions On April 30, 2010, we signed a purchase and sale agreement with Omya, Inc. to purchase certain generating, transmission and distribution assets located in the State of Vermont. Under this agreement, we will pay approximately $33.2 million for the transmission and distribution assets and generating assets comprised of four hydroelectric generating stations. The agreement contains usual and customary purchase-and-sale terms and conditions and is contingent upon federal and state regulatory approvals. The transaction is currently scheduled to close in the fourth quarter of 2010.

Dividends Our dividend level is reviewed by our Board of Directors on a quarterly basis. It is our goal to ensure earnings in future years are sufficient to maintain our current dividend level.

Dividend Reinvestment Plan Our Dividend Reinvestment Plan used Treasury shares as the source of common shares to meet reinvestment obligations since July 2007. These elections resulted in additional cash flow of $1 million to $2 million annually. In September 2009, we ceased using Treasury shares and began using original issue shares to meet reinvestment obligations under the plan.

Cash Flow Risks Based on our current cash forecasts, we will require outside capital in addition to cash flow from operations and our $40 million and $15 million unsecured revolving credit facilities in order to fund our business over the next few years. Prolonged upheaval in the capital markets could negatively impact our ability to obtain outside capital on reasonable terms. If we were ever unable to obtain needed capital, we would re-evaluate and prioritize our planned capital expenditures and operating activities. In addition, 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. An extended Vermont Yankee plant outage could involve cost recovery via our forced outage insurance policy and recoveries under the PCAM but in general would not be expected to materially impact our financial results, if the costs are recovered in retail rates in a timely fashion. 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 power source interruption; required prepayments for power purchases; and increases in performance assurance requirements. It is important to note, however, that our alternative regulation plan sets bands around the earnings in our regulated business, which ensures, in part, that they will not fall below prescribed levels. See Retail Rates and Alternative Regulation above for additional information related to mechanisms designed to mitigate our utility-related risks. See Retail Rates and Alternative Regulation above for additional information related to mechanisms designed to mitigate our utility-related risks.

Global Economic Conditions We expect to have access to liquidity in the capital markets when needed at reasonable rates. We have access to a $40 million unsecured revolving credit facility and a $15 million unsecured revolving credit facility with two different lending institutions. However, sustained turbulence in the global credit markets could limit or delay our access to capital. As part of our enterprise risk management program, we routinely monitor our risks by reviewing our investments in and exposure to various firms and financial institutions.

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Financing

We also have a 364-day, $15 million unsecured revolving credit facility with a different lending institution pursuant to a credit agreement dated December 30, 2009. The purpose and obligation under this credit agreement are the same as described above. At June 30, 2010, there were no borrowings or letters of credit outstanding under the credit facility.

Common Equity Issue: On November 6, 2009, we filed a Registration Statement with the SEC on Form S-3, requesting the ability to offer, from time to time and in one or more offerings, up to $55 million of our common stock. On December 4, 2009, the SEC declared the Registration Statement to be effective. On January 15, 2010, we filed a Prospectus Supplement with the SEC noting that we entered into an equity distribution agreement that allowed us to issue up to $45 million of shares under an “at-the-market” program. As of June 30, 2010, 582,831 shares have been issued, yielding net proceeds of $11.8 million.

First Mortgage Bond Issue: On July 15, 2010, we entered into a commitment to issue $40 million of first mortgage bonds at 5.89 percent on June 15, 2011 in a private placement transaction, pending internal and regulatory approvals. The proceeds will be used to help finance our capital expenditures, debt retirements, investments in Transco and other corporate purposes.

Capital Commitments Our business is capital-intensive because annual construction expenditures are required to maintain the distribution system. Capital expenditures for the next five years are expected to range from $39 million to $62 million annually over the five-year period, including an estimated total of more than $60 million for CVPS SmartPower TM . As of June 30, 2010, capital expenditures were $12.1 million.

Smart Grid Stimulus Grant: On October 27, 2009, the DOE announced that Vermont’s electric utilities will receive $69 million in federal stimulus funds to deploy advanced metering, new customer service enhancements and grid automation. As a participant on Vermont’s smart grid stimulus application, we expect to receive a grant of over $31 million. The agreement includes provisions for funding and other requirements.

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Off-balance-sheet arrangements We do not use off-balance-sheet financing arrangements, such as securitization of receivables, nor obtain access to assets through special purpose entities. We have letters of credit that are described in Financing above. Until the second quarter of 2010, we leased most vehicles and related equipment under operating lease agreements. These operating lease agreements are described in Note 12 - Commitments and Contingencies.

Commitments and Contingencies We have material power supply commitments for the purchase of power from VYNPC and Hydro-Quebec. These are described in Power Supply Matters below.

We own equity interests in VELCO and Transco, which require us to pay a portion of their operating costs under our transmission agreements. We own an equity interest in VYNPC and are obligated to pay a portion of VYNPC’s operating costs under a purchased power contract (“PPA”) between VYNPC and Entergy-Vermont Yankee. We also own equity interests in three nuclear plants that have completed decommissioning. We are responsible for paying our share of the costs associated with these plants. Our equity ownership interests are described in Note 3 - Investments in Affiliates.

On December 20, 2005, we completed the sale of Catamount, our wholly owned subsidiary, to CEC Wind Acquisition, LLC, a company established by Diamond Castle Holdings, a New York-based private equity investment firm (“Diamond Castle”). Under the terms of the agreements with Catamount and Diamond Castle, we agreed to indemnify them, and certain of their respective affiliates as described in Note 12 - Commitments and Contingencies.

OTHER BUSINESS RISKS

Our Enterprise Risk Management (“ERM”) program serves to protect our assets, safeguard shareholder investment, ensure compliance with applicable legal requirements and effectively serve our customers. The ERM program is intended to provide an integrated and effective governance structure for risk identification and management and legal compliance within the company. Among other things, we use metrics to assess key risks, including the potential impact and likelihood of the key risks.

We are also subject to regulatory risk and wholesale power market risk related to our Vermont electric utility business.

Regulatory Risk: Historically, electric utility rates in Vermont have been based on a utility’s costs of service. Accordingly, we are entitled to charge rates that are sufficient to allow us an opportunity to recover reasonable operation and capital costs and a reasonable return on investment to attract needed capital and maintain our financial integrity, while also protecting relevant public interests. We are subject to certain accounting standards that allow regulated entities, in appropriate circumstances, to establish regulatory assets and liabilities, and thereby defer the income statement impact of certain costs and revenues that are expected to be realized in future rates. There is no assurance that the PSB will approve the recovery of all costs incurred for the operation, maintenance, and construction of our regulated assets, as well as a return on investment. Adverse regulatory changes could have a significant impact on future results of operations and financial condition. See Critical Accounting Policies and Estimates.

The State of Vermont has passed several laws since 2005 that impact our regulated business and will continue to impact it in the future. Some changes include requirements for renewable energy supplies and opportunities for alternative regulation plans. See Recent Energy Policy Initiatives below.

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Power Supply Risk: Our contract for power purchases from VYNPC ends in March 2012, but there is a risk that the plant could be shut down earlier than expected if Entergy-Vermont Yankee determines that it is not economical to continue operating the plant, or due to environmental concerns. Hydro-Quebec contract deliveries end in 2016, but the average level of deliveries decreases by approximately 19 percent after 2012, and by approximately 84 percent after 2015. There is a risk that future sources available to replace these contracts may not be as reliable and the price of such replacement power could be significantly higher than what we have in place today. However, the company has been planning for the expiration of these contracts for several years, and a robust effort, described further below, is in place to ensure a safe, reliable, environmentally beneficial and relatively affordable energy supply going forward.

Entergy-Vermont Yankee has submitted a renewal application with the NRC and an application for a CPG with the PSB for a 20-year extension of the Vermont Yankee plant operating license. Entergy-Vermont Yankee also needs approval from the PSB and Vermont Legislature to continue to operate beyond 2012. Significant hurdles may prevent its relicensing. Potential operating, transparency and communication issues related to the plant have raised serious concerns among regulators and members of the Vermont Legislature, including some who have called for its temporary or permanent shutdown. An intervenor in the CPG case has requested that the PSB order a shutdown of the Vermont Yankee plant due to recent leaks at the site. The PSB has opened a new docket to consider that request.

If the Vermont Yankee plant is shut down for any reason prior to the end of its operating license, we would lose the economic benefit of an energy volume equal to close to 50 percent of our total committed supply and have to acquire replacement power resources for approximately 40 percent of our estimated power supply needs. Based on forward market prices as of June 30, 2010, the incremental replacement cost of lost power is estimated to average $17 million annually over the remaining life of the contract. We are not able to predict whether there will be an early shutdown of the Vermont Yankee plant or whether the PSB would allow timely and full recovery of increased costs related to such shutdown. An early shutdown, depending upon the specific circumstances, could involve cost recovery via the outage insurance described above and recoveries under the PCAM but, in general, would not be expected to materially impact financial results, if the costs are recovered in retail rates in a timely fashion.

We are exploring other supply sources as well. Beginning in May 2008, HQ-Production engaged with Northeast Utilities (“NU”) and NSTAR on a plan to bundle a new 1,200 MW New England/Quebec interconnection and power purchase agreement and have submitted the concept to the FERC for approval. HQ-Production and NU have expressed the expectation that there will be sufficient volume in that bundled power purchase agreement to allow the participation of other load-serving New England utilities to participate, including Vermont utilities. The Vermont utilities are expected to join in the negotiations of the agreement, which continue in 2010. Agreements to renew purchases over existing interconnections are also possible. We recently signed a memorandum of agreement, a precursor to a final contract for ongoing Hydro-Quebec supplies. We cannot predict whether a new contract will ultimately be achieved and approved or if approved, the quantities of power to be purchased or the price terms of any purchases. However, we view the signing of this memorandum as a positive step toward continuation of our decades-long relationship with Hydro-Quebec and for the good of Vermont’s consumers.

Wholesale Power Market Price Risk: Our material power supply contracts are with Hydro-Quebec and VYNPC. These contracts comprise the majority of our total annual energy (mWh) purchases. If one or both of these sources becomes unavailable for a period of time, there could be exposure to high wholesale power prices and that amount could be material.

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We are responsible for procuring replacement energy during periods of scheduled or unscheduled outages of our power sources. Average market prices at the times when we purchase replacement energy might be higher than amounts included for recovery in our retail rates. We have forced outage insurance through March 21, 2011 to cover additional costs, if any, of obtaining replacement power from other sources if the Vermont Yankee plant experiences unplanned outages. The Power Cost Adjustment Mechanism within our alternative regulation plan allows recovery of power costs.

Market Risk: See Item 3 - Quantitative and Qualitative Disclosures About Market Risk.

ACCOUNTING MATTERS

Critical accounting policies and estimates Our financial statements are prepared in accordance with U.S. GAAP, requiring us to make estimates and judgments that affect reported amounts of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of the Condensed Consolidated Financial Statements. Our critical accounting policies and estimates are described in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2009.

Health Care Reform Legislation On March 23, 2010, the federal Patient Protection and Affordable Care Act (“the Act”) was signed into law. The Act is a comprehensive health care reform bill that includes revenue-raising provisions for nearly $400 billion over 10 years through tax increases on high-income individuals, excise taxes on high-cost group health plans, and new fees on selected health-care-related industries. In addition, on March 25, 2010, the Health Care and Education Affordability Reconciliation Act of 2010 was passed into law, which modifies certain provisions of the Act.

We continue to evaluate the future impact of the legislation on our employee benefit plans; however, we are currently unable to predict the impact on our financial statements or whether we will experience any significant change in future benefit cost trends.

Other See Note 1 - Business Organization and Summary of Significant Accounting Policies to the accompanying Notes to Condensed Consolidated Financial Statements.

RESULTS OF OPERATIONS

The following is a detailed discussion of the results of operations for the second quarter and first six months of 2010. This should be read in conjunction with the Condensed Consolidated Financial Statements and accompanying notes included in this report.

Our second quarter 2010 earnings decreased $4.1 million, or 35 cents per diluted share of common stock compared to the same period in 2009. Earnings for the first six months of 2010 decreased by $6.7 million, or 58 cents per diluted share of common stock, compared to the same period in 2009. The table that follows provides a reconciliation of the primary year-over-year variances in diluted earnings per share for 2010 versus 2009. The earnings per diluted share for each variance shown below are non-GAAP measures:

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Reconciliation of Earnings Per Diluted Share
	Second Quarter			First Six Months
	2010 vs. 2009			2010 vs. 2009
2009 Earnings per diluted share	$	0.46		$	1.04

Year-over-Year Effects on Earnings:
Higher maintenance expenses		(0.09	)		(0.25	)
Higher other operating expenses		(0.13	)		(0.19	)
Lower operating revenues		(0.13	)		(0.12	)
Lower other income, net		(0.07	)		(0.06	)
Health Care Reform/Medicare Part D - Income tax impact		0.00			(0.06	)
Higher equity in earnings of affiliates		0.02			0.07
Lower purchased power expense		0.07			0.06
Other		(0.02	)		(0.03	)
2010 Earnings per diluted share	$	0.11		$	0.46

Operating Revenues The majority of operating revenues is generated through retail electric sales. Retail sales are affected by weather and economic conditions since these factors influence customer use. Resale sales represent the sale of power into the wholesale market normally sourced from owned and purchased power supply in excess of that needed by our retail customers. The amount of resale revenue is affected by the availability of excess power for resale, the types of sales we enter into and the price of those sales. Operating revenues and related mWh sales are summarized below:

	Three months ended June 30									Six months ended June 30
	Revenues									Revenues
	(in thousands)					mWh Sales				(in thousands)					mWh Sales
	2010		2009			2010		2009		2010		2009			2010		2009
Residential	$	32,839	$	30,736			215,868		213,622	$	72,475	$	69,702			486,293		497,716
Commercial		26,572		24,703			200,878		193,596		53,217		50,540			404,687		402,629
Industrial		7,676		7,476			85,865		85,622		16,965		16,286			183,294		181,902
Other		498		467			1,631		1,590		990		937			3,229		3,176
Total retail sales		67,585		63,382			504,242		494,430		143,647		137,465			1,077,503		1,085,423
Resale sales		6,984		17,131			160,204		244,586		18,323		31,064			383,304		448,434
Provision for rate refund		2,201		(1,101	)		0		0		2,326		(1,101	)		0		0
Other operating revenues		3,167		3,215			0		0		6,648		5,926			0		0
Total operating revenues	$	79,937	$	82,627			664,446		739,016	$	170,944	$	173,354			1,460,807		1,533,857

2010 vs. 2009

Operating revenues decreased by $2.7 million in the second quarter and $2.4 million in the first six months of 2010 as compared to the same periods in 2009 as a result of the following:

Retail sales increased $4.2 million in the second quarter and $6.2 million in the first six months resulting primarily from a 5.58 percent base rate increase effective Jan. 1, 2010 and the recovery of 2008 major storm costs through the ESAM, partly offset by lower customer usage, mostly due to warmer winter weather in 2010.

Resale sales decreased $10.1 million in the second quarter and $12.7 million in the first six months mostly due to lower 2010 contract prices associated with the sale of our excess energy and a decrease in volumes sold due to the scheduled refueling outages at the Vermont Yankee plant and Millstone Unit #3.

The provision for rate refund is related to over- or under-collections of power, production and transmission costs as defined by the power cost adjustment clause of our alternative regulation plan. The increase in the first six months included the favorable impact of $0.5 million of net deferrals in 2010 vs. $1.1 million of net deferrals in 2009 and the amounts returned to customers increased to $1.8 million in 2010 vs. none in 2009.

§	Other operating revenues increased $0.7 million in the first six months mostly from higher levels of mutual aid to other utilities and the sale of renewable energy credits.

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Operating Expenses Operating expenses increased $1 million in the second quarter and $4.6 million in the first six months of 2010 as compared to 2009. Significant variances in operating expenses on the Condensed Consolidated Statements of Income are described below.

Purchased Power - affiliates and other: Purchased power expense and volume is summarized below:

	Three months ended June 30										Six months ended June 30
	Purchases										Purchases
	(in thousands)						mWh purchases				(in thousands)						mWh purchases
	2010			2009			2010		2009		2010			2009			2010		2009
VYNPC	$	10,161		$	15,709			234,611		383,062	$	26,389		$	31,442			622,166		769,773
Hydro-Quebec		15,140			15,155			221,840		207,971		31,748			32,214			489,465		476,133
Independent Power Producers		5,811			5,763			53,782		54,887		12,157			11,672			103,976		102,839
Subtotal long-term contracts		31,112			36,627			510,233		645,920		70,294			75,328			1,215,607		1,348,745
Other purchases		6,489			1,812			92,103		14,039		8,855			4,192			106,064		27,442
Loss contingency amortizations		(299	)		(299	)		0		0		(598	)		(598	)		0		0
Nuclear decommissioning		353			325			0		0		683			654			0		0
Other		(444	)		140			0		0		(305	)		639			0		0
Total purchased power	$	37,211		$	38,605			602,336		659,959	$	78,929		$	80,215		$	1,321,671	$	1,376,187

2010 vs. 2009

Purchased power expense decreased $1.4 million in the second quarter and $1.3 million in the first six months of 2010 compared to the same periods in 2009 as a result of the following:

Purchased power costs under long-term contracts decreased $5.5 million in the second quarter and $5 million in the first six months of 2010, due primarily to lower output at the Vermont Yankee plant related to a scheduled refueling outage and lower capacity costs from Hydro-Quebec offset by an increase in purchases from Independent Power Producers.

§	Other purchases increased $4.7 million in the second quarter and first six months due to the purchase of replacement power for the scheduled refueling outages at Vermont Yankee and Millstone Unit #3.

§	Nuclear decommissioning costs are associated with our ownership interests in Maine Yankee, Connecticut Yankee and Yankee Atomic. These costs are based on FERC-approved tariffs.

Other costs decreased $0.6 million in the second quarter and $0.9 million in the first six months. These Other costs are amortizations and deferrals based on PSB-approved regulatory accounting, including those for incremental energy costs related to Millstone Unit #3 scheduled refueling outages and deferrals for our share of nuclear insurance refunds received by VYNPC. There were no nuclear insurance refunds in the second quarter of 2010.

Transmission - affiliates: These expenses represent our share of the net cost of service of Transco 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 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.

The decreases of $1.3 million for the second quarter and $2.4 million for the first six months were principally due to higher NOATT reimbursements under the VTA, related to the overall transmission expansion in New England, partially offset by higher charges under the VTA resulting from Transco’s capital projects.

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. The increases of $1 million for the second quarter and $2.5 million for the first six months primarily resulted from higher rates and overall transmission expansion in New England.

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. The increases of $1.7 million for the second quarter and $2.1 million for the first six months were primarily due to $2.7 million of higher net regulatory amortizations in 2010, primarily related to the recovery of 2008 major storm costs and $0.6 million of lower reserves for uncollectible accounts in 2010, primarily due to a customer bankruptcy in 2009.

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Maintenance: These expenses are associated with maintaining our electric distribution system and include costs of our jointly owned generation and transmission facilities. The increases of $1.8 million for the second quarter and $5.1 million for the first six months were largely due to higher service restoration costs related to major storms in February and May 2010.

Taxes other than income: This is related primarily to property taxes and payroll taxes. The increase of $0.6 million for the second quarter and $1.2 million for the first six months were largely due to increases in property taxes.

Income tax expense: Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences, tax credits, tax settlements and changes in valuation allowances for the periods. The effective combined federal and state income tax rate for 2010 is 43.5 percent compared to 34.3 percent for 2009. The variance includes the impact of the Patient Protection and Affordable Care Act, as modified by the Health Care and Education Reconciliation Act, which represents 7 percent of the 2010 effective tax rate.

As required, in March 2010 we recorded an increase of $2.1 million in regulatory assets and an increase of $2.8 million in deferred income taxes on the Condensed Consolidated Balance Sheets, resulting in an increase of $0.7 million in income tax expense on the Condensed Consolidated Statements of Income, related to postretirement medical expenditures that will not be deductible in the future. See Note 11 – Pension and Postretirement Medical Benefits for additional information.

Other Income These items represent the non-operating activities of our utility business and the operating and non-operating activities of our non-regulated business through CRC. CRC’s earnings were less than $0.1 million for the second quarter and $0.1 million for the first six months of both 2010 and 2009. Significant variances in line items that comprise other income on the Condensed Consolidated Statements of Income are described below.

Equity in earnings of affiliates: These are earnings on our equity investments including VELCO, Transco and VYNPC. The increase of $0.7 million for the second quarter and $1.6 million in the six months is principally due to the $20.8 million investment that we made in Transco in December 2009.

Other Deductions: These items include supplemental retirement benefits and insurance, including changes in the cash surrender value of variable life insurance policies, non-utility expenses relating to rental water heaters, and miscellaneous other deductions. The increase of $0.8 million for the second quarter and $0.7 million for the first six months is primarily related to changes in the cash surrender value of variable life insurance policies included in our Rabbi Trust. In 2010, there were market losses versus market gains in 2009.

POWER SUPPLY MATTERS

Power Supply Management Our power supply portfolio includes a mix of baseload and dispatchable resources. These resources serve our retail electric load requirements and any wholesale sale obligations into which we enter as part of a hedging strategy. We manage our power supply portfolio by attempting to optimize the economic value of these resources and to balance our power supplies and load obligations.

Our power supply management philosophy is to balance the desire to minimize costs while incurring conservative levels of liquidity risk. Risk mitigation strategies are built around minimizing both forward price risks and operational risks while strictly limiting the potential for both our collateral exposure and inefficient deployment of capital. Other risks are mitigated by the power and transmission cost recovery process contained in the PCAM (see Retail Rates and Alternative Regulation). We also mitigate price risks through limited wholesale transactions that hedge market price risk, as discussed below. In addition, we purchased outage insurance, currently effective through early 2011, to help cover unexpected costs of major unplanned Vermont Yankee outages that could cause the plant to curtail deliveries under the current PPA. Participating in Financial Transmission Rights (FTRs) auctions provides us with opportunities to economically hedge our exposure to congestion charges that result from constraints at points on the transmission system between locations where generators are sited and where load is served. FTRs are awarded to successful bidders in periodic auctions that are administered by ISO-New England.

Our current power forecast suggests we have excess energy supply through 2011. We attempt to sell most of our excess energy in the forward market at fixed prices in order to reduce market price volatility and gain a measure of revenue certainty while remaining strictly within potential collateral exposure limits. In October 2009, we executed a forward sale of expected excess supply for calendar year 2010. We are currently preparing to make forward transactions that will bring our resources into closer balance with expected customer demand through at least the second quarter of 2011.

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Attaining an investment-grade credit rating expanded the available collateral limits with our current counterparties and we expect our credit upgrade will attract new counterparties that are willing to transact with us. However, regardless of collateral limits and available counterparties, we expect to maintain our practice of constraining net transaction volumes with individual counterparties to mitigate potential collateral exposures during stressed market conditions.

Future Power Supply Long-term contracts with Vermont Yankee and Hydro-Quebec provide the majority of our current power supply. There is some risk that future sources available to replace these contracts may be less reliable and impose significantly higher prices than current portfolio resources although supplies are more than adequate in the region and prices have moderated significantly since the peaks experienced in 2008. These contracts are described in more detail in Note 12 - Commitments and Contingencies.

Our contract for power purchases from VYNPC ends in March 2012, but there is a risk that we could lose this resource if the plant shuts down before that date. An early shutdown could cause our customers to lose the economic benefit of an energy volume of close to 50 percent of our total committed supply and we would have to acquire replacement power resources for approximately 40 percent of our estimated power supply needs. Based on forward market prices as of June 30, 2010, the incremental replacement cost of lost power is estimated to average $17 million annually over the remaining life of the contract. We are not able to predict whether there will be an early shutdown of the Vermont Yankee plant or whether the PSB would allow timely and full recovery of increased costs of such shutdown. An early shutdown, depending upon the specific circumstances, could involve cost recovery via the outage insurance described above and recoveries under the PCAM but, in general, would not be expected to materially impact financial results if the costs are recovered in retail rates in a timely fashion.

At this time, Entergy-Vermont Yankee is attempting to overcome these concerns, and in April 2010, we began a new round of negotiations on a new contract. We rejected Entergy-Vermont Yankee’s last public proposal, but both parties continue to exchange information and proposals. The parties are attempting to negotiate a purchased power contract in order that the state will have the value of such an agreement to consider should the other 20-year extension issues that have emerged be resolved. We cannot predict the outcome at this time.

Under the terms of sale of the plant in 2002, Entergy-Vermont Yankee also agreed to a Revenue Sharing Agreement (“RSA”) for the period 2012 through 2022. The RSA will yield revenue to us on a certain MW portion of the plant’s actual output whenever the average annual unit revenue exceeds a “strike price” that is established by formula beginning at $61/ mWh in 2012. Should the plant be relicensed and operate through March 2022, the effect of the RSA will be to provide a price cap-like effect (at the level of the strike price) on the net cost of a purchase of an equal quantity of power made at market prices. Protection from upward price volatility above the level of the RSA represents a significant economic value to our consumers.

Contract deliveries from Hydro-Quebec will decline by approximately 19 percent after 2012, by approximately 84 percent after 2015 and will cease in 2016. The first reduction will serve to reduce the amount of the Company’s power supply expected through October 2015. Hydro-Quebec is engaged in the addition of approximately 4,000 MW of hydroelectric capacity in Quebec largely targeted for export partially via increased transmission capacity into the New England market. We are negotiating with Hydro-Quebec for future purchases that could supplement or replace our current purchases from them.

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RECENT ENERGY POLICY INITIATIVES

In 2005, the state of Vermont created a renewable energy mandate under the Sustainably Priced Energy Development Program (“SPEED”). The primary SPEED goal is that, by January 1, 2012, Vermont utilities produce or purchase energy equal to 5 percent of the 2005 electricity sales, plus sales growth since then, from small-scale solar, wind, hydro and methane energy production (“SPEED resources”).

An additional SPEED goal is that, by 2017, SPEED resources account for 20 percent of Vermont’s electricity sales. The SPEED goal is a statewide target, rather than something specific to each utility. We believe we are on pace to achieve the 2012 SPEED targets.

In May, 2009, the Vermont Legislature amended the SPEED law to create a “Feed-In Tariff” (FIT) rate for SPEED resources smaller than 2.2 MW in capacity. FIT rates are available for a maximum of 50 MW of capacity. The incremental cost of electricity from FIT projects is to be borne proportionately by all Vermont utilities except Washington Electric Cooperative, which was exempted from the program.

In May 2010, the Vermont Legislature amended the SPEED law to allow existing farm methane generators (including our “Cow Power” generators) to qualify for the FIT. We supported this action.

The 2010 Legislature also repealed a Vermont law that precluded hydroelectric facilities with capacity above 80 MW from being considered as “renewable” resources. While there are no such facilities in Vermont, CVPS purchases power from Hydro-Quebec, which does operate facilities larger than 80 MW. We anticipate no immediate impact from this change in policy, but we expect that it will become a factor in future policy and contract deliberations.

RECENT ACCOUNTING PRONOUNCEMENTS AND TECHNICAL DEVELOPMENTS

Dodd-Frank Act On July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Act”) was signed into law. While the Act has broad implications to the financial services industry, there are some new mandates for public companies that may require changes in corporate governance, compensation, government regulation of the over-the-counter derivatives market, accounting and other areas. The regulations implementing the Act have not yet been drafted; however the SEC has begun issuing concept releases under certain provisions of the Act. We are uncertain to what degree this legislation may affect our business in the future, but we are evaluating these additional regulatory requirements and the potential impact on our financial statements.

Also, see Part I, Item 1, Note 1 - Business Organization and Summary of Significant Accounting Policies to the accompanying Condensed Consolidated Financial Statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For the six months ended June 30, 2010, there were no material changes from the disclosures included in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2009 except as shown below.

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Power-related derivatives We account for some of our power contracts as derivatives under FASB’s guidance for derivatives and hedging. These derivatives are described in Management's Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies and Estimates. Summarized information related to the fair value of power contract derivatives is shown in the table below (dollars in thousands):

	Forward			Financial
	Energy			Transmission			Hydro-Quebec
	Contracts			Rights			Sellback #3			Total
Total fair value at December 31, 2009	$	269		$	134		$	(149	)	$	254
Gains and losses (realized and unrealized)
Included in earnings		2,092			27			0			2,119
Included in Regulatory and other assets/liabilities		2,435			58			149			2,642
Purchases, sales, issuances and net settlements		(2,092	)		(94	)		0			(2,186	)
Total fair value at June 30, 2010	$	2,704		$	125		$	0		$	2,829

Estimated fair value at June 30, 2010 for changes in projected market price:
10 percent increase	$	1,306		$	144		$	(275	)	$	1,175
10 percent decrease	$	4,101		$	108		$	0		$	4,209

Pursuant to a PSB-approved Accounting Order, changes in fair value of all power-related derivatives are recorded as deferred charges or deferred credits on the Condensed Consolidated Balance Sheets depending on whether the change in fair value is an unrealized loss or unrealized gain, with an offsetting amount recorded as a decrease or increase in the related derivative asset or liability.

Equity Market Risk As of June 30, 2010, our pension trust held marketable equity securities in the amount of $52.5 million, our postretirement medical trust funds held marketable equity securities in the amount of $8.5 million, our Millstone Unit #3 decommissioning trust held marketable equity securities of $3.5 million and our Rabbi Trust held variable life insurance policies with underlying marketable equity securities of $2.2 million. These equity investments experienced positive performance in 2009 and negative performance in the market downturn of 2008. Also see Management’s Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources, and Note 11 - Pension and Postretirement Medical Benefits for additional information.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Management of the company, under the supervision and with participation of our Chief Executive Officer and Principal Financial and Accounting Officer, conducted an evaluation of the effectiveness of the design and operation of the company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934), as of June 30, 2010. Based on this evaluation, our Chief Executive Officer and Principal Financial and Accounting Officer concluded that, as of June 30, 2010, the company’s disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting There were no changes in internal control over financial reporting that occurred during the quarter ended June 30, 2010 that have materially affected, or are reasonably likely to materially affect, the company’s internal control over financial reporting.

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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, results of operations or cash flows.
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, 2009, which could materially affect our business, financial condition or future 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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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	CENTRAL VERMONT PUBLIC SERVICE CORPORATION
	(Registrant)
By	/s/ Pamela J. Keefe
	Pamela J. Keefe Sr. Vice President, Chief Financial Officer, and Treasurer