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 March 31, 2012

¨	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		03-0111290
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

77 Grove Street, Rutland, Vermont		05701
(Address of principal executive offices)		(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 x No ¨

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

Large accelerated filer ¨		Accelerated filer x

Non-accelerated filer ¨ (Do not check if a smaller reporting company)		Smaller reporting company o

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 April 30, 2012 there were outstanding 13,650,572 shares of Common Stock, $6 Par Value.

CENTRAL VERMONT PUBLIC SERVICE CORPORATION

Form 10-Q for Period Ended March 31, 2012

Table of Contents

PART I. Financial Information:
				Page
	Item 1.	Financial Statements
			Unaudited Condensed Consolidated Statements of Income	4
			Unaudited Condensed Consolidated Statements of Comprehensive Operations	5
			Unaudited Condensed Consolidated Statements of Cash Flows	6
			Unaudited Condensed Consolidated Balance Sheets	7
			Unaudited Condensed Consolidated Statement of Changes in Common Stock Equity	9
			Notes to Unaudited Condensed Consolidated Financial Statements	10

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		35

	Item 3.	Quantitative and Qualitative Disclosures about Market Risk		49

	Item 4.	Controls and Procedures		50

PART II. Other Information:

	Item 1.	Legal Proceedings		51

	Item 1A.	Risk Factors		51

	Item 6.	Exhibits		51

SIGNATURES				53

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GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations or acronyms that are found in the report:

Current or former CVPS Companies, Segments or Investments
CRC	Catamount Resources Corporation
Custom	Custom Investment Corporation
CV or CVPS	Central Vermont Public Service Corporation
East Barnet	Central Vermont Public Service Corporation - East Barnet Hydroelectric, Inc.
Transco	Vermont Transco LLC
VELCO	Vermont Electric Power Company, Inc.
VETCO	Vermont Electric Transmission Company, Inc.
VYNPC	Vermont Yankee Nuclear Power Corporation

Regulatory and Other Authorities
DOE	United States Department of Energy
DPS	Vermont Department of Public Service
EPA	Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
IRS	Internal Revenue Service
NRC	Nuclear Regulatory Commission
PSB	Vermont Public Service Board
SEC	Securities and Exchange Commission
VANR	Vermont Agency of Natural Resources

Other
AFUDC	Allowance for funds used during construction
AOCL	Accumulated other comprehensive loss
ARP MOU	Memorandum of Understanding with the DPS on the Alternative Regulation II Plan
ARRA	American Recovery and Reinvestment Act
CDA	Connecticut Development Authority Bonds
Connecticut Yankee	Connecticut Yankee Atomic Power Company
CVPS SmartPower®	CV’s “smart grid” program designed to modernize and automate the electrical grid, provide automated meter reading, and empower consumers to make better energy choices. The plan includes two-way communications systems and strategies to introduce new rate designs, including dynamic pricing and demand response programs.
CVPS SmartPower® MOU	Memorandum of Understanding with the DPS on CVPS SmartPower®
DNC	Dominion Nuclear Connecticut
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act
DUP	Vermont's Distributed Utility Planning
EEI	Edison Electric Institute
EEU	Vermont Energy Efficiency Utility
Entergy	Entergy Corporation
Entergy-Vermont Yankee	Entergy Nuclear Vermont Yankee, LLC
EPACT	Federal Energy Policy Act of 2005
EPS	Earnings per share
ERM	Enterprise Risk Management
ESAM	Earnings sharing adjustment mechanism
FASB	Financial Accounting Standards Board
FCM	Forward Capacity Market
Fortis	Fortis Inc. and Fortis subsidiaries involved in the terminated proposed merger transaction
Fortis subsidiaries	FortisUS Inc. and Cedar Acquisition Sub Inc.

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FTRs	Financial Transmission Rights
Gaz Métro	Gaz Métro Limited Partnership
GMP	Green Mountain Power Corporation
HQUS PPA	Long-term power purchase and sale agreement with H.Q. Energy Services (U.S) Inc.
IASB	International Accounting Standards Board
IFRS	International Financial Reporting Standards
IPPs	Independent Power Producers
ISO-NE	New England Independent System Operator
kWh	Kilowatt-hours
Maine Yankee	Maine Yankee Atomic Power Company
Moody's	Moody's Investors Service
MOU	Memorandum of Understanding
MW	Megawatt
MWh	Megawatt-hours
NOATT	NEPOOL Open Access Transmission Tariff
NYSE	New York Stock Exchange
OASIS	Open Access Same-time Information System
Omnibus Stock Plan	Central Vermont Public Service Corporation Omnibus Stock Plan
Omya	Omya Industries, Inc.
PCAM	Power supply and transmission-by-others cost adjustment mechanism
PCB	Polychlorinated biphenyl contamination
Pension Plan	A qualified, non-contributory, defined-benefit pension plan
Phase I	Hydro-Québec Phase I
Phase II	Hydro-Québec Phase II
PPA	Purchased power contract
PPACA	The Federal Patient Protection and Affordable Care Act
PSNH	Public Service Company of New Hampshire
PTF	Pool Transmission Facility
Readsboro	Readsboro Electric Department
ROA	Return on Assets
ROE	Return on Equity
RTO	Regional Transmission Organization
SERP	Officers' Supplemental Retirement Plan
SMD	Standard Market Design
SPEED	Sustainably Priced Energy Development Program for Vermont Utilities
Staffing MOU	Memorandum of Understanding with the DPS to review staffing level
TbyO	Transmission by Others costs
The Exchange Act	Securities and Exchange Act of 1934
TPH	Total petroleum hydrocarbons
TSR	Total Shareholder Return
U.S. GAAP	Generally Accepted Accounting Principles in the United States of America
VEDA	Vermont Economic Development Authority
Vermont Marble	Vermont Marble Power Division of Omya Industries, Inc.
VIDA	Vermont Industrial Development Authority Bonds
VJO	Vermont Joint Owners
VPPSA	Vermont Public Power Supply Authority
VTA	Vermont Transmission Agreement (1991)
VY PPA	Purchased power contract between VYNPC and Entergy-Vermont Yankee
Yankee Atomic	Yankee Atomic Electric Company

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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 March 31
	2012			2011
Operating Revenues	$	96,242		$	97,085

Operating Expenses
Purchased Power - affiliates		15,565			17,411
Purchased Power		24,923			23,941
Production		2,576			3,144
Transmission - affiliates		3,888			2,257
Transmission - other		7,455			7,104
Other operation		15,030			18,594
Maintenance		6,280			5,707
Depreciation		4,346			4,485
Taxes other than income		5,296			4,657
Income tax expense		3,138			2,857
Total Operating Expenses		88,497			90,157

Utility Operating Income		7,745			6,928

Other Income
Equity in earnings of affiliates		6,800			6,941
Allowance for equity funds during construction		80			56
Other income		726			703
Other deductions		(434	)		(654	)
Merger-related expenses		(242	)		0
Income tax expense		(2,220	)		(2,302	)
Total Other Income		4,710			4,744

Interest Expense
Interest on long-term debt		3,502			3,144
Other interest		122			129
Allowance for borrowed funds during construction		(44	)		(26	)
Total Interest Expense		3,580			3,247

Net Income		8,875			8,425
Dividends declared on preferred stock		92			92
Earnings available for common stock	$	8,783		$	8,333

Per Common Share Data:
Basic earnings per share	$	0.65		$	0.62
Diluted earnings per share	$	0.65		$	0.62
Average shares of common stock outstanding - basic		13,491,377			13,353,973
Average shares of common stock outstanding - diluted		13,570,720			13,406,926
Dividends declared per share of common stock	$	0.23		$	0.46

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

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)

(unaudited)

	Three months ended March 31
	2012		2011
Net Income	$	8,875	$	8,425

Other comprehensive income, net of tax:

Defined benefit pension and postretirement medical plans:
Portion reclassified through amortizations, included in benefit costs and recognized in net income:
Actuarial losses, net of income taxes of $1 in 2012 and $65 in 2011		1		95

Change in funded status of pension, postretirement medical and other benefit plans, net of income taxes of $0 in 2012 and $26 in 2011		0		38

Comprehensive income adjustments		1		133

Total comprehensive income	$	8,876	$	8,558

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

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)

(unaudited)

	Three months ended March 31
Cash flows provided by:	2012			2011
OPERATING ACTIVITIES
Net Income	$	8,875		$	8,425
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of affiliates		(6,800	)		(6,941	)
Distributions received from affiliates		4,943			3,562
Depreciation		4,346			4,485
Deferred income taxes and investment tax credits		4,855			2,057
Regulatory and other deferrals and amortization		330			4,104
Non-cash employee benefit plan costs		1,822			1,761
Other non-cash expense and (income), net		1,146			(2,833	)
Changes in assets and liabilities:
Decrease in accounts receivable and unbilled revenues		1,717			6,584
(Decrease) increase in accounts payable		(2,956	)		599
Change in prepaid and accrued income taxes		3,015			14,349
Increase in other current assets		(1,424	)		(803	)
Increase in special deposits and restricted cash		(292	)		0
Employee benefit plan funding		(179	)		(8	)
Decrease in other current liabilities		(2,338	)		(3,032	)
Increase in other long-term liabilities and other		1,104			73
Net cash provided by operating activities		18,164			32,382
INVESTING ACTIVITIES
Construction and plant expenditures		(9,590	)		(10,004	)
Reimbursements of restricted cash - bond proceeds		4,139			7,004
Project reimbursement from DOE		1,058			375
Investments in available-for-sale securities		(288	)		(345	)
Proceeds from sale of available-for-sale securities		208			300
Other investing activities		(505	)		(154	)
Net cash used for investing activities		(4,978	)		(2,824	)
FINANCING ACTIVITIES
Net proceeds from the issuance of common stock		1,771			361
Common and preferred dividends paid		(3,192	)		(3,161	)
Proceeds from revolving credit facility and other short-term borrowings		41,199			11,384
Repayments under revolving credit facility and other short-term borrowings		(53,329	)		(25,079	)
Common stock offering and debt issue costs		0			(128	)
Reduction in capital lease and other financing activities		355			(482	)
Net cash used for financing activities		(13,196	)		(17,105	)
Net change in cash and cash equivalents		(10	)		12,453
Cash and cash equivalents at beginning of the period		1,734			2,676
Cash and cash equivalents at end of the period	$	1,724		$	15,129

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

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(dollars in thousands, except share data)

	March 31, 2012		December 31, 2011
	(unaudited)
ASSETS
Utility plant
Utility plant	$	690,391	$	684,509
Less accumulated depreciation		300,769		297,441
Utility plant, net of accumulated depreciation		389,622		387,068
Property under capital leases, net		3,165		3,395
Construction work-in-progress		26,006		23,376
Nuclear fuel, net		2,727		2,749
Total utility plant, net		421,520		416,588

Investments and other assets
Investments in affiliates		181,832		179,974
Non-utility property, less accumulated depreciation ($3,177 in 2012 and $3,190 in 2011)		2,263		2,280
Millstone decommissioning trust fund		6,362		5,950
Restricted cash		499		2,550
Other		7,438		7,063
Total investments and other assets		198,394		197,817

Current assets
Cash and cash equivalents		1,724		1,734
Restricted cash		2,833		4,619
Special deposits		0		5
Accounts receivable, less allowance for uncollectible accounts ($3,431 in 2012 and $3,305 in 2011)		27,246		26,984
Accounts receivable - affiliates, less allowance for uncollectible accounts		1,618		650
Unbilled revenues		17,985		21,638
Materials and supplies, at average cost		7,845		7,537
Prepayments		12,037		13,966
Deferred income taxes		9,936		11,862
Power-related derivatives		13		4
Regulatory assets		2,783		2,605
Other deferred charges - regulatory		14,594		9,202
Other deferred charges and other assets		722		1,533
Other current assets		1,648		2,289
Total current assets		100,984		104,628

Deferred charges and other assets
Regulatory assets		45,480		46,381
Other deferred charges - regulatory		2,743		4,623
Other deferred charges and other assets		5,509		6,228
Total deferred charges and other assets		53,732		57,232

TOTAL ASSETS	$	774,630	$	776,265

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

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(dollars in thousands, except share data)

	March 31, 2012			December 31, 2011
	(unaudited)
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock, $6 par value, 19,000,000 shares authorized, 15,693,048 issued and 13,563,975 outstanding at March 31, 2012 and 15,602,091 issued and 13,473,018 outstanding at December 31, 2011	$	94,158		$	93,613
Other paid-in capital		97,916			96,040
Accumulated other comprehensive loss		(185	)		(186	)
Treasury stock, at cost, 2,129,073 shares at March 31, 2012 and December 31, 2011		(48,436	)		(48,436	)
Retained earnings		132,806			127,123
Total common stock equity		276,259			268,154
Preferred and preference stock not subject to mandatory redemption		8,054			8,054
Long-term debt		228,448			240,578
Capital lease obligations		2,242			2,471
Total capitalization		515,003			519,257

Current liabilities
Accounts payable		8,699			7,157
Accounts payable - affiliates		10,614			15,133
Nuclear decommissioning costs		1,462			1,433
Power-related derivatives		8,955			4,940
Other deferred credits - regulatory		816			1,047
Other current liabilities		48,089			49,369
Total current liabilities		78,635			79,079

Deferred credits and other liabilities
Deferred income taxes		103,276			100,314
Deferred investment tax credits		2,079			2,132
Nuclear decommissioning costs		3,454			3,827
Asset retirement obligations		3,859			3,806
Accrued pension and benefit obligations		42,242			40,981
Other deferred credits - regulatory		3,451			3,081
Other deferred credits and other liabilities		22,631			23,788
Total deferred credits and other liabilities		180,992			177,929

Commitments and contingencies (Note 13)

TOTAL CAPITALIZATION AND LIABILITIES	$	774,630		$	776,265

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

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN COMMON STOCK EQUITY

(in thousands, except share data)

(unaudited)

	Common Stock				Treasury Stock
	Shares Issued		Amount		Shares			Amount			Other Paid-in Capital		Accumulated Other Comprehensive Loss			Retained Earnings			Total
Balance, December 31, 2011		15,602,091	$	93,613		(2,129,073	)	$	(48,436	)	$	96,040	$	(186	)	$	127,123		$	268,154
Net income																	8,875			8,875
Other comprehensive income														1						1
Dividend reinvestment plan		7,187		43								212								255
Stock options exercised		83,770		502								1,014								1,516
Share-based compensation:
Common & nonvested shares												590								590
Performance share plans												56								56
Dividends declared:
Common - $0.23 per share																	(3,100	)		(3,100	)
Cumulative non-redeemable preferred stock																	(92	)		(92	)
Amortization of preferred stock issuance expense												4								4
Balance, March 31, 2012		15,693,048	$	94,158		(2,129,073	)	$	(48,436	)	$	97,916	$	(185	)	$	132,806		$	276,259

	Common Stock				Treasury Stock
	Shares Issued		Amount		Shares			Amount			Other Paid-in Capital			Accumulated Other Comprehensive Loss			Retained Earnings			Total
Balance, December 31, 2010		15,470,217	$	92,821		(2,129,073	)	$	(48,436	)	$	94,462		$	(232	)	$	134,113		$	272,728
Net income																		8,425			8,425
Other comprehensive income															133						133
Dividend reinvestment plan		16,313		98								263									361
Share-based compensation:
Common & nonvested shares		4,699		28								(25	)								3
Performance share plans		5,987		36								(207	)								(171	)
Dividends declared:
Common - $0.46 per share																		(6,143	)		(6,143	)
Cumulative non-redeemable preferred stock																		(92	)		(92	)
Amortization of preferred stock issuance expense												4									4
Balance, March 31, 2011		15,497,216	$	92,983		(2,129,073	)	$	(48,436	)	$	94,497		$	(99	)	$	136,303		$	275,248

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

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - BUSINESS ORGANIZATION

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 160,000 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-NE, 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 C.V. Realty, Inc., East Barnet and CRC. We have equity ownership interests in VYNPC, VELCO, Transco, Maine Yankee, Connecticut Yankee and Yankee Atomic.

Pending Merger with Gaz Métro On July 11, 2011, CVPS, Gaz Métro Limited Partnership (“Gaz Métro”) and Danaus Vermont Corp., an indirect wholly owned subsidiary of Gaz Métro (“Merger Sub”), entered into an Agreement and Plan of Merger (the “Merger Agreement”).

Upon the terms and subject to the conditions set forth in the Merger Agreement, unanimously approved by the boards of directors of CVPS and Gaz Métro Inc., the general partner of Gaz Métro, Merger Sub will merge with and into CVPS (the “Merger”), with CVPS continuing as the surviving corporation and an indirect wholly owned subsidiary of Gaz Métro.

Pursuant to the Merger Agreement, upon the closing of the Merger, each issued and outstanding share of CVPS common stock (other than shares which are held by any wholly owned subsidiary of the Company or in the treasury of the Company or which are held by Gaz Métro or Merger Sub, or any of their respective wholly owned subsidiaries, all of which shall cease to be outstanding and shall be canceled and none of which shall receive any payment with respect thereto, and dissenting shares) will automatically be converted into the right to receive in cash, without interest, $35.25 per share (the “Merger Consideration”), less any applicable withholding taxes.

Completion of the Merger is subject to various customary conditions. They include, among others, approval by CVPS shareholders; expiration or termination of the applicable Hart-Scott-Rodino Act waiting period; receipt of all required regulatory approvals from, among others, the FERC and the PSB; and the absence of any governmental action challenging or seeking prohibition of the Merger; and the absence of any material adverse effect with respect to CVPS. Each party’s obligation to consummate the Merger is also subject to additional customary conditions including, subject to certain exceptions, the accuracy of the representations and warranties of the other party and performance in all material respects by the other party of its obligations.

The Merger Agreement contains certain termination rights for both CVPS and Gaz Métro and further provides that upon termination of the merger agreement under specified circumstances, CVPS may be required to reimburse Gaz Métro the amount of $19.5 million paid to CVPS by Gaz Métro to reimburse CVPS for a termination payment to FortisUS, Inc. in connection with the termination of a prior merger agreement between CVPS and FortisUS, Inc. A party desiring to terminate must provide written notice of termination to the other party. A notice of termination may be provided at any time after July 11, 2012, if regulatory approval has been obtained at that time but the transaction has not closed in accordance with the Agreement, or January 11, 2013, if regulatory approval has not been obtained by the 12-month anniversary of the Merger Agreement and the transaction has not closed by the 18-month anniversary.

Regulatory Approvals: On September 2, 2011, CVPS, Danaus Vermont Corp., Northern New England Energy Corporation, for itself and as agent for Gaz Métro and the direct and indirect upstream parents of Gaz Métro, GMP, and Vermont Low Income Trust for Electricity, Inc. filed a petition with the PSB for approval of the proposed merger announced by the companies on July 12, 2011. The PSB established a review schedule, beginning with a workshop held on October 14, 2011 and a public hearing on November 1, 2011. Written testimony and discovery responses have been filed with the PSB and technical hearings ended on April 4, 2012. Briefs were submitted on April 23, 2012, and reply briefs were submitted on May 4, 2012. There is no time limit within which the PSB must issue its decision whether to approve the merger, but we hope for a decision that would allow closing in June 2012.

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In addition, we made other regulatory filings seeking approval of the Merger, including with the NRC, the FERC, the Federal Trade Commission, Federal Communications Commission, the Committee on Foreign Investments in the U.S., New York State Public Service Commission, New Hampshire Public Utilities Commission, and the Maine Public Utility Commission. On September 26, 2011, in connection with the Hart Scott-Rodino filing, the Federal Trade Commission granted early termination of the statutory waiting period, which effectively allows us to continue planning for the Merger. On November 22, 2011, we received approvals from the Committee on Foreign Investments in the U.S. and the Maine Public Utility Commission. Also, on November 22, 2011 the New York State Public Service Commission issued a declaratory ruling of no jurisdiction. On March 6, 2012, we received approval from the FERC and on March 7, 2012, we received approval from the Federal Communications Commission for the transfer of control of our radio licenses.

On March 26, 2012 an MOU concerning the merger was reached with the DPS. The parties reached an agreement regarding, among other things, VELCO ownership and governance, the sharing of merger-related savings between customers and the post-merger company, and the satisfaction of obligations imposed on CVPS by an order in 2001 that created a “windfall sharing mechanism” that would be triggered by the Merger Agreement. The DPS has recommended that the PSB approve the Merger in accordance with the amendments outlined in the MOU.

Reimbursement of Termination Fee: On September 29, 2011, as a result of the approval by the company’s shareholders of the Merger, Gaz Métro reimbursed CVPS for the full amount of the Fortis Termination Payment of $17.5 million plus expenses of FortisUS Inc. of $2 million. Such reimbursement was required pursuant to the terms of CVPS’s Merger Agreement with Gaz Métro.

Under the Merger Agreement, CVPS is required to repay the amount of such reimbursement to Gaz Métro in the event the Merger Agreement is terminated because of either the issuance of an order or injunction prohibiting the Merger (other than as a result of the action by a governmental entity with respect to required regulatory approvals) or the breach by CVPS of its representations, warranties or covenants contained in the Merger Agreement. If the Merger Agreement is terminated for any other reason, CVPS is not required to repay such amount to Gaz Métro. While CVPS believes it is unlikely that the Merger Agreement will be terminated on a basis giving rise to a requirement to repay Gaz Métro and, accordingly, believes that the likelihood of such repayment is remote, the final accounting for the reimbursement cannot be determined until the Merger is either completed or terminated. Accordingly, the reimbursement has been recorded as an Other Current Liability until that time.

Terminated Merger Agreement with Fortis On May 27, 2011, CVPS, FortisUS Inc., Cedar Acquisition Sub Inc., a direct wholly owned subsidiary of Fortis and Fortis Inc., the ultimate parent of Fortis (“Ultimate Parent”), entered into an Agreement and Plan of Merger (the “Fortis Merger Agreement”).

On July 11, 2011, prior to entering into the Merger Agreement with Gaz Métro, CVPS terminated the Fortis Merger Agreement. In accordance with the Fortis Merger Agreement, on July 12, 2011, CVPS paid FortisUS Inc. $19.5 million (the “Fortis Termination Payment”), consisting of a termination fee of $17.5 million and expenses of FortisUS Inc. of $2 million. These amounts have been recorded as a component of Other Income on the Condensed Consolidated Statement of Income in 2011. The Merger Agreement with Gaz Métro required Gaz Métro to reimburse CVPS for its payment of the Fortis Termination Payment immediately following the approval of the Merger Agreement by CVPS shareholders. It also provides that CVPS will be required to pay Gaz Métro the full amount of the Fortis Termination Payment reimbursement if the Merger Agreement is terminated under certain circumstances.

Vendor claim: In June 2011, following our announcement of the Fortis Merger Agreement, we received notice of a claim for up to $4.8 million from a former financial advisor, related to the pending merger. We have assessed the claim and do not believe that any amount is owed. In order to resolve the dispute, on December 23, 2011, we filed a declaratory judgment action in the United States District Court for the District of Vermont, seeking a declaration that we do not owe any amount to the vendor. The complaint was served on the financial advisor on April 11, 2012.

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Litigation Related to Merger Agreement On or about June 2, 2011, a lawsuit captioned David Raul v. Lawrence Reilly, et al., Civil Division Docket No. 377-6-11-RDCV, was filed in the Superior Court of Vermont, Rutland Unit against CVPS and members of the CVPS Board of Directors. The lawsuit also named as defendants FortisUS Inc. and one of its affiliates. The Raul complaint, which purported to be brought on behalf of a class consisting of the public stockholders of CVPS, alleged that CVPS’s directors breached their fiduciary duties by entering into the Fortis Merger Agreement for a price that is alleged to be unfair, as the result of a process alleged to be unfair and inadequate, with material conflicts of interest and so as to benefit themselves, and including no-solicitation, matching rights and termination fee provisions alleged to be designed to ensure that no competing offers would emerge for CVPS. The Raul complaint also included a claim of aiding and abetting against CVPS and the Fortis entities. The Raul complaint sought, among other things, injunctive relief against the proposed transaction with Fortis as well as other equitable relief, damages and attorneys’ fees and costs. On June 23, 2011, following the announcement of an offer received from Gaz Métro, David Raul filed an amended class action complaint repeating his earlier allegations and claims but also referring to this development and claiming that the CVPS Board should terminate the Fortis Merger Agreement and negotiate a new deal with Gaz Métro.

On or about June 17, 2011 and June 20, 2011, two additional complaints (Civil Division Docket Nos. 417-6-11-RDCV and 425-6-11-RDCV, respectively) were filed in the Superior Court of Vermont, Rutland Unit, containing claims and allegations similar to those in the original Raul complaint and seeking similar relief on behalf of the same putative class. These complaints were filed, respectively, by IBEW Local 98 Pension Fund and by Adrienne Halberstam, Jacob Halberstam and Sarah Halberstam.

On July 13, 2011, a lawsuit captioned Howard Davis v. Central Vermont Public Service, et al., Case No. 5:11-CV-181 was filed in the United States District Court for the District of Vermont against CVPS and members of the CVPS Board of Directors. The lawsuit also named as defendants Gaz Métro Limited Partnership and one of its affiliates. The Davis complaint, which purported to be brought on behalf of a class consisting of the public stockholders of CVPS, alleged that CVPS’s directors breached their fiduciary duties by, among other things, allegedly failing to undertake an adequate sales process prior to the Fortis Merger Agreement, entering into the Merger Agreement with Gaz Métro at an unfair price and pursuant to an unfair process, engaging in self-dealing, and by including various “deal protection devices” in the Merger Agreement. The Davis complaint also included a claim for aiding and abetting against CVPS and the Gaz Métro entities. The Davis complaint sought injunctive relief and other equitable relief against the proposed transaction with Gaz Métro, as well as attorneys’ fees and costs.

On July 22, 2011, the Halberstam plaintiffs in the state case filed an amended complaint in the Vermont Superior Court, Rutland Unit, which added Gaz Métro Limited Partnership and one of its affiliates as defendants in addition to the defendants named in the original complaint. The amended complaint contained claims and allegations similar to those in the Davis complaint and sought similar relief.

On August 2, 2011, an Amended Class Action Complaint was filed in the Davis action reiterating the previous claims of breaches of fiduciary duty and adding claims that the Company’s proxy materials regarding the Merger are materially misleading and/or incomplete in various respects, in alleged violation of fiduciary duties and the federal securities laws. The Amended Class Action Complaint in the Davis action seeks injunctive and other equitable relief against the proposed transaction with Gaz Métro, damages, and attorneys’ fees and costs.

On or about August 17, 2011, the three cases pending in the Superior Court of Vermont were consolidated by court order, in accordance with a stipulation that had been filed by the parties. The court also entered orders stating that defendants need only respond to a consolidated amended complaint to be filed, denying a motion for expedited discovery that had been brought by the plaintiffs, and staying all discovery until the legal sufficiency of a consolidated amended complaint could be determined.

On August 23, 2011, IBEW moved for leave to file a consolidated amended complaint in the state court proceedings. The proposed consolidated amended complaint contained claims for breach of fiduciary duty against the members of the CVPS Board of Directors in connection with both the Fortis Merger Agreement and the subsequent Gaz Métro Merger Agreement, including claims that the proxy materials provided in connection with the proposed shareholder vote on the Merger were misleading and/or incomplete, and that the CVPS Board had violated its fiduciary duties. The proposed consolidated amended complaint also contained claims for aiding and abetting fiduciary breaches against CVPS and Gaz Métro. The proposed consolidated amended complaint sought, among other relief, an injunction against consummation of the Gaz Métro Merger and damages, including but not limited to damages allegedly resulting from CVPS’s payment of a termination fee in connection with the termination of the Fortis Merger Agreement.

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On September 1, 2011, plaintiff in the Davis action filed a motion seeking a preliminary injunction against the September 29, 2011 shareholder vote that was scheduled in connection with the Merger. On September 16, 2011, defendants in the Davis action filed motions to dismiss the Amended Class Action Complaint.

On September 19, 2011, CVPS and the other defendants in the Davis action entered into a memorandum of understanding with the Davis plaintiff regarding an agreed in principle class-wide settlement of the Davis action, subject to court approval. In the memorandum of understanding, the parties agreed that CVPS would make certain disclosures to its shareholders relating to the Merger, in addition to the information contained in the initial Proxy Statement, in exchange for a settlement of all claims. Pursuant to the memorandum of understanding, CVPS subsequently issued a Supplemental Proxy statement that included the additional disclosures. On November 28, 2011, the parties to the Davis action entered into a finalized settlement agreement consistent with the terms of the memorandum of understanding, which was then submitted to the court by the Davis plaintiff together with a request for preliminary approval. The IBEW plaintiff subsequently moved to intervene in the Davis lawsuit for the purpose of objecting to the proposed settlement agreement. On December 21, 2011, the court held a hearing on the request for preliminary approval and on the IBEW’s motion to intervene. The request for preliminary approval was denied without prejudice to refile. The IBEW motion to intervene was also denied without prejudice.

The Davis plaintiff filed a revised request for preliminary approval of the settlement agreement. By order dated April 10, 2012, the court 1) approved, for purposes of settlement only, certification of the Davis lawsuit as a class action under the federal rules; 2) certified plaintiff Howard Davis as the Class representative; 3) scheduled a Fairness Hearing for July 11, 2012, to determine a number of issues including whether the court should approve the Settlement Agreement and a request by Plaintiff's counsel for attorney's fees.

Meanwhile, a putative class action complaint captioned IBEW Local 98 Pension Fund, Adrienne Halberstam, Jacob Halberstam, Sarah Halberstam, and David Raul v. Central Vermont Public Service, et al., Case No. 5:11-CV-222 was filed in the United States District Court for the District of Vermont against CVPS, Gaz Métro, and members of the CVPS Board of Directors. This federal IBEW complaint, dated September 15, 2011, contained claims of breach of fiduciary duty and inadequate proxy statement disclosures that are substantially similar to those contained in the proposed consolidated amended complaint filed by the same plaintiffs in the Superior Court of Vermont. The federal IBEW complaint also included allegations of violations of the Securities Exchange Act of 1934. Defendants filed motions to dismiss and, on December 7, 2011, the federal IBEW complaint was amended. The amended complaint contained substantially similar claims and allegations. Defendants have moved to dismiss the IBEW amended complaint and briefing on that motion was completed.

On January 12, 2012, the parties to the state court lawsuits filed a stipulation for dismissal without prejudice of those proceedings. On January 24, 2012, the state court entered an order stating that the state court lawsuits would be dismissed without prejudice unless it received a filed objection by January 31, 2012. No such objection was filed.

On March 19, 2012, the court dismissed the federal claims in the IBEW amended complaint without prejudice. The court did not rule on the motions to dismiss the state law claims in the amended complaint but raised the issue of whether the Court should exercise supplemental jurisdiction over the state law claims. The court requested the parties to submit supplemental briefing on the issue of supplemental jurisdiction. On March 22, 2012, and in response to a stipulated motion by the parties, the court ordered that the IBEW federal plaintiffs file any amendment of their federal claims by April 6, 2012 or the federal claims would be dismissed with prejudice. The IBEW plaintiffs filed their second amended complaint on April 6, 2012. On May 2, 2012, the defendants filed a motion to dismiss the federal claims in the IBEW plaintiffs’ second amendment complaint. The court has suspended briefing on the issue of whether it should exercise supplemental jurisdiction over the IBEW plaintiffs’ state law claims, subject to further order, until it has the opportunity to rule on a motion to dismiss the federal claims in the IBEW plaintiffs’ second amended complaint.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation These unaudited financial statements have been prepared pursuant to the rules and regulations of the SEC and in accordance with U.S. GAAP. The accompanying unaudited condensed consolidated financial statements contain all normal, recurring adjustments considered necessary to present fairly the financial position as of March 31, 2012, and the results of operations and cash flows for the three months ended March 31, 2012 and 2011. The results of operations for the interim periods presented herein may not be indicative of the results that may be expected for any other period or the full year. These condensed consolidated 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, 2011.

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We consider subsequent 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.

Financial Statement Presentation The focus of the Condensed Consolidated Statements of Income is on the regulatory treatment of revenues and expenses of the regulated utility as opposed to other enterprises where the focus is on income from continuing operations. Operating revenues and expenses (including related income taxes) are those items that ordinarily are included in the determination of revenue requirements or amounts recoverable from customers in rates. Operating expenses represent the costs of rendering service to be covered by revenue, before coverage of interest and other capital costs. Other income and deductions include non-utility operating results, certain expenses judged not to be recoverable through rates, related income taxes and costs (i.e. interest expense) that utility operating income is intended to cover through the allowed rate of return on equity rather than as a direct cost-of-service revenue requirement.

The focus of the Condensed Consolidated Balance Sheets is on utility plant and capital because of the capital-intensive nature of the regulated utility business. The prominent position given to utility plant, capital stock, retained earnings and long-term debt supports regulated ratemaking concepts in that utility plant is the rate base and capitalization (including long-term debt) is the basis for determining the rate of return that is applied to the rate base.

Please refer to the Glossary of Terms following the Table of Contents for frequently used abbreviations and acronyms that are found in this report.

Regulatory Accounting Our utility operations are regulated by the PSB, FERC and the Connecticut Department of Public Utility and Control, 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 FASB’s 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 should 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 increasing competition that restricts a company’s ability to establish prices to recover specific costs, and a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. See Note 9 - Retail Rates and Regulatory Accounting for additional information.

Supplemental Financial Statement Data Supplemental financial information for the accompanying financial statements is provided below.

Prepayments: The components of Prepayments on the Consolidated Balance Sheets follow (dollars in thousands):

	March 31, 2012		December 31, 2011
Taxes	$	9,187	$	12,550
Insurance		1,625		434
Miscellaneous		1,225		982
Total	$	12,037	$	13,966

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Other current liabilities: The components of Other current liabilities on the Consolidated Balance Sheets follow (dollars in thousands):

	March 31, 2012		December 31, 2011
Deferred compensation plans and other	$	771	$	764
Accrued employee-related costs		2,651		3,244
Other taxes and Energy Efficiency Utility		6,218		4,633
Cash concentration account - outstanding checks		510		4,131
Obligation under capital leases		918		917
Provision for rate refund		1,087		390
Fortis termination reimbursement		19,500		19,500
Tropical storm Irene expense accrual		1,139		1,178
Accrued interest		4,351		942
Miscellaneous accruals		10,944		13,670
Total	$	48,089	$	49,369

NOTE 3 - EARNINGS PER SHARE

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 for the three months ended March 31(dollars in thousands, except share information):

	Three months ended March 31
	2012			2011
Numerator for basic and diluted EPS:
Net income	$	8,875		$	8,425
Dividends declared on preferred stock		(92	)		(92	)
Net income available for common stock	$	8,783		$	8,333

Denominators for basic and diluted EPS:
Weighted-average basic shares of common stock outstanding		13,491,377			13,353,973
Dilutive effect of stock options		53,125			23,089
Dilutive effect of performance shares		26,218			29,864
Weighted-average diluted shares of common stock outstanding		13,570,720			13,406,926

Stock Options: There were no outstanding stock options excluded from the diluted shares calculation for the three months ended March 31, 2012 or March 31, 2011.

Performance Shares: Outstanding performance shares totaling 7,800 were excluded from the computation of diluted shares for the three months ended March 31, 2012 because the performance share measures were not met or there was an antidilutive impact. Outstanding performance shares totaling 47,306 were excluded from the diluted EPS calculation for the three months ended March 31, 2011.

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NOTE 4 - INVESTMENTS IN AFFILIATES

VELCO Summarized consolidated financial information (including Transco) for the three months ended March 31 follows (dollars in thousands):

	Three months ended March 31
	2012			2011

Operating revenues	$	32,239		$	34,227
Operating income	$	18,898		$	19,715

Income before non-controlling interest and income tax	$	15,830		$	15,769
Less members' non-controlling interest in income		14,399			14,537
Less income tax		507			467
Net income	$	924		$	765

Company's common stock ownership interest		47.10	%		47.05	%
Company's equity in net income	$	219		$	360

Accounts payable to VELCO were $5.2 million at March 31, 2012 and $7.3 million at December 31, 2011.

Transco Summarized financial information (included above in VELCO’s summarized consolidated financial information) for the three months ended March 31 follows (dollars in thousands):

	Three months ended March 31
	2012			2011
Operating revenues	$	32,268		$	34,411
Operating income	$	19,556		$	20,502
Net income	$	16,001		$	16,137

Company's direct ownership interest		36.59	%		36.68	%
Company's equity in net income	$	6,525		$	6,525

Transmission services provided by Transco are billed to us under the 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 NOATT and other agreements.

Transco’s billings to us primarily include the VTA and charges and reimbursements under the NOATT. Included in Transco’s operating revenues above are transmission services to us amounting to $3.9 million for the three months ended March 31, 2012 and $2.3 million for the three months ended March 31, 2011. These amounts are included in Transmission - affiliates on our Condensed Consolidated Statements of Income. Accounts payable to Transco were $1.4 million at March 31, 2012 and $1.8 million at December 31, 2011.

VYNPC Summarized financial information at December 31 follows (dollars in thousands):

	Three months ended March 31
	2012			2011
Operating revenues	$	43,703		$	48,973
Operating (loss) income	$	(156	)	$	(253	)
Net income	$	90		$	91

Company's common stock ownership interest		63.64	%		58.85	%
Company's equity in net income	$	54		$	53

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VYNPC’s revenues shown in the table above include sales to us of $15.2 million for the three months ended March 31, 2012 and $17.1 million for the three months ended March 31, 2011. These amounts are included in Purchased power - affiliates on our Condensed Consolidated Statements of Income. Accounts payable to VYNPC were $3.9 million at March 31, 2012 and $5.9 million at December 31, 2011. The VY PPA terminated on March 21, 2012.

On March 30, 2012, VYNPC repurchased its common stock from Central Maine Power. This increased our equity ownership percentage from 58.85 percent to 63.64 percent.

DOE Litigation: VYNPC has been seeking recovery of fuel storage-related costs from the DOE. Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the disposal of spent nuclear fuel and high-level radioactive waste. VYNPC, as required by that Act, signed a contract with the DOE (the “Standard Contract”) to provide for the disposal of spent nuclear fuel and high-level radioactive waste from its nuclear generation station beginning no later than January 31, 1998. The Standard Contract obligated VYNPC to pay a one-time fee of approximately $39.3 million for disposal costs for all nuclear fuel used through April 6, 1983 (the “pre-1983 fuel”), and a fee payable quarterly equal to one mil per kilowatt-hour of nuclear generated and sold electricity after April 6, 1983. Except for the obligation to pay the one-time fee and the right to claims relating to the DOE’s defaults under the Standard Contract with respect to the pre-1983 fuel, the Standard Contract was assigned to Entergy effective with the sale of the plant in 2002. VYNPC filed its lawsuit against the government for the DOE’s breach in the U.S. Court of Federal Claims on July 30, 2002.

Through 2011, VYNPC has accumulated $143 million in an irrevocable trust to be used exclusively for meeting this obligation ($144.7 million including accrued interest) at some future date, provided the DOE complies with the terms of the aforementioned Standard Contract. Under the terms of the sale agreement, VYNPC retained the spent fuel trust fund assets, the related obligation to make this payment to the DOE when and if it becomes due, and its claims against DOE associated with the pre-1983 fuel. VYNPC collected the funds from us and other wholesale utility customers, under FERC-approved wholesale rates, and our share of these payments was collected from our retail customers.

On October 22, 2008, the trial judge presiding over VYNPC’s case granted a motion for partial summary judgment filed by Entergy, and dismissed VYNPC’s case. The judge ruled that VYNPC lacked any actionable claim that was not transferred to Entergy in the sale of the plant. On April 3, 2009, the trial judge reissued his decision to dismiss VYNPC’s case under a special rule that would allow VYNPC to immediately appeal the decision to the United States Court of Appeals for the Federal Circuit (“the Federal Circuit”). However, on September 2, 2009, the Federal Circuit remanded the matter to the trial judge with instructions to vacate his most recent ruling. The effect of this action was to suspend VYNPC’s appeal until the trial judge issued a final order in the related Entergy proceeding. The order was issued on October 15, 2010, and on December 13, 2010, VYNPC filed a Notice of Appeal to the Court of Appeals for the Federal Circuit.

In its appeal, VYNPC filed a legal brief on May 12, 2011, and it was followed by amicus curiae (“friend of the court”) briefs from the state of Vermont on May 19, 2011 and October 24, 2011. Reply briefs were filed by the DOE on December 5, 2011, VYNPC on December 22, 2011, and Entergy Nuclear-Vermont Yankee on January 4, 2012. The appeal is still pending.

We expect that our share of these awards, if any, would be credited to our retail customers; however, we are currently unable to predict the outcome of this case.

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 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 current and non-current regulatory assets and nuclear decommissioning liabilities. These amounts are adjusted when revised estimates are provided. At March 31, 2012, we had regulatory assets of $0.3 million for Maine Yankee, $3.3 million for Connecticut Yankee and $1.3 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 $0.3 million for the first three months of 2012 and $0.4 million for the first three months of 2011. These amounts are included in Purchased power - affiliates on our Condensed Consolidated Statements of Operations.

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

In 2006, the United States Court of Federal Claims issued judgment in the first phase of spent fuel litigation. Maine Yankee was awarded $75.8 million in damages through 2002, Connecticut Yankee was awarded $34.2 million through 2001 and Yankee Atomic was awarded $32.9 million through 2001. This decision was appealed in December 2006, and all three companies filed notices of cross appeals. In August 2008, the United States Court of Appeals for the Federal Circuit reversed the award of damages and remanded the cases back to the trial court. The remand directed the trial court to apply the acceptance rate in the 1987 annual capacity reports when determining damages.

A final ruling on the remanded case in favor of the three companies was issued on September 7, 2010. Maine Yankee was awarded $81.7 million, Connecticut Yankee was awarded $39.7 million and Yankee Atomic was awarded $21.2 million. The DOE filed an appeal on November 8, 2010 and the three Yankee companies filed cross-appeals on November 19, 2010.

Oral arguments before the United States Court of Appeals for the Federal Circuit were held on November 7, 2011. Interest on the judgments does not start to accrue until the appeals have been decided. Our share of the claimed damages of $3.2 million is based on our ownership percentages described above. A decision is expected during the second quarter of 2012.

The Court of Federal Claims’ original decision established the DOE’s responsibility for reimbursing Maine Yankee for its actual costs through 2002 and Connecticut Yankee and Yankee Atomic for their actual costs through 2001. These costs are related to the incremental spent fuel storage, security, construction and other expenses of the spent fuel storage installation. Although the decision did not resolve the question regarding damages in subsequent years, the decision did support future claims for the remaining spent fuel storage installation construction costs.

In December 2007, the three companies filed a second round of damage cases against the DOE. On July 1, 2009, Maine Yankee, Connecticut Yankee and Yankee Atomic filed details related to the claimed costs for damages incurred for periods subsequent to the original case discussed above. In this second phase of claims, Maine Yankee claimed $43 million since January 1, 2003 and Connecticut Yankee and Yankee Atomic claimed $135.4 million and $86.1 million, respectively since January 1, 2002. For all three companies the damages were claimed through December 31, 2008. Our share of the claimed damages in this second round is $6.6 million is based on our ownership percentages described above.

The trial on this second round of claims began October 11, 2011. The DOE has made post-trial filings to keep the record in the cases open while they continue to review documents produced in discovery in an attempt to provide additional trial testimony on selected issues. The three companies have asked for the trial records to be closed in all cases and for a post-trial briefing schedule to be set.

On Thursday March 1, 2012, an order was issued in response to the DOE’s motion to compel additional discovery in the Connecticut Yankee and Maine Yankee portions of the case. The Yankee Atomic evidentiary portion has already been closed. This decision closes discovery on Connecticut Yankee, grants potential but limited additional discovery on privileged documents in the Maine Yankee case, and, provides a post-trial briefing schedule that allows the cases to be ready for decision by early May 2012.

Due to the complexity of these issues and the potential for further appeals, the three companies cannot predict the timing of the final determinations or the amount of damages that will actually be received. Each of the companies’ respective FERC settlements requires that damage payments, net of taxes and further spent fuel trust funding, if any, be credited to wholesale ratepayers including us. We expect that our share of these awards, if any, would be credited to our retail customers.

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NOTE 5 - FINANCIAL INSTRUMENTS

The estimated fair value of financial instruments at March 31 follows (dollars in thousands):

	March 31, 2012				December 31, 2011
		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Power contract derivative assets (includes current portion)	$	13	$	13	$	4	$	4
Power contract derivative liabilities (includes current portion)	$	8,955	$	8,955	$	4,940	$	4,940

Long-term debt (level 2):
First mortgage bonds (includes current portion)	$	187,500	$	234,952	$	187,500	$	239,026
Industrial/Economic Development bonds	$	40,800	$	44,485	$	40,800	$	42,691
Credit facility borrowings	$	148	$	148	$	12,278	$	12,278

At March 31, 2012, our power-related derivatives consisted of FTRs and forward energy contracts. Related unrealized losses of $9 million were recorded as other deferred charges – regulatory on the Consolidated Balance Sheet and there were no related unrealized gains. At December 31, 2011, our power-related derivatives consisted of FTRs and forward energy contracts. Related unrealized losses of $4.9 million were recorded as other deferred charges – regulatory on the Consolidated Balance Sheet and there were no related unrealized gains. For a discussion of the valuation techniques used for power contract derivatives see Note 6 - Fair Value.

The fair values of our first mortgage bonds and fixed rate industrial/economic development 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 as the carrying values of those instruments approximate fair value because of their short duration. The carrying values of our variable rate industrial/economic development 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 6 - Fair Value.

NOTE 6 - FAIR VALUE

We use the FASB’s guidance for fair value measurements. The guidance establishes a single, authoritative definition of fair value, prescribes methods for measuring fair value, establishes a fair value hierarchy based on the inputs used to measure fair value and expands disclosures about the use of fair value measurements; however, the guidance does not expand the use of fair value accounting. The 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. The FASB requires 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 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 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 cash equivalents that consist of money market funds, commercial paper held in restricted cash and 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 financial transmission rights. There were no changes to our Level 3 fair value measurement methodologies during 2012 and 2011.

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 March 31, 2012
	Level 1		Level 2		Level 3		Total
Assets:
Millstone decommissioning trust fund
Investments in securities:
Marketable equity securities	$	1,767	$	3,102			$	4,869
Marketable debt securities
Corporate bonds				358				358
U.S. Government issued debt securities (Agency and Treasury)				1,003				1,003
State and municipal				60				60
Other				32				32
Total marketable debt securities				1,453				1,453
Cash equivalents and other				40				40
Total investments in securities		1,767		4,595				6,362
Restricted cash - long-term				499				499
Cash equivalents				768				768
Restricted cash				2,833				2,833
Power-related derivatives - current						13		13
Total assets	$	1,767	$	8,695	$	13	$	10,475

Liabilities:
Power-related derivatives - current					$	8,955	$	8,955
Power-related derivatives - long term
Total liabilities	$	0	$	0	$	8,955	$	8,955

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	Fair Value as of December 31, 2011
	Level 1		Level 2		Level 3		Total
Assets:
Millstone decommissioning trust fund
Investments in securities:
Marketable equity securities	$	1,621	$	2,847			$	4,468
Marketable debt securities
Corporate bonds				356				356
U.S. Government issued debt securities (Agency and Treasury)				963				963
State and municipal				88				88
Other				30				30
Total marketable debt securities				1,437				1,437
Cash equivalents and other				45				45
Total investments in securities		1,621		4,329				5,950
Restricted cash - long-term				2,550				2,550
Cash equivalents		434						434
Restricted cash				4,619				4,619
Power-related derivatives - current					$	4		4
Power-related derivatives - long term								0
Total assets	$	2,055	$	11,498	$	4	$	13,557

Liabilities:
Power-related derivatives - current					$	4,940	$	4,940
Power-related derivatives - long term							$	0
Total liabilities	$	0	$	0	$	4,940	$	4,940

Millstone Decommissioning Trust Our primary valuation technique to measure the fair value of our nuclear decommissioning trust investments is the market approach. We own a share of the qualified decommissioning fund and cannot validate a publicly quoted price at the qualified fund level. 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 March 31, 2012 or 2011.

Cash Equivalents and Restricted Cash The market approach is used to measure the fair values of money market funds and other short-term investments 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 quoted prices for these funds; therefore they are classified as Level 2. We are able to obtain a quoted price for our 30-day commercial paper held in restricted cash; however, the quote was from a less active market. We have concluded that this investment does not qualify for Level 1 and is reflected as Level 2. Cash equivalents are included in cash and cash equivalents on the Condensed Consolidated Balance Sheets.

Power-related Derivatives We have historically had three types of derivative assets and liabilities: forward energy contracts, FTRs, and a power-related option contract. At March 31, 2012, our derivatives consisted of forward energy contracts and FTRs. At March 31, 2011, our derivatives consisted of FTRs only. 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. All models are calibrated to market prices on a quarterly basis. Since many of the valuation inputs are not observable in the market, we have classified our derivative assets and liabilities as Level 3. The valuations obtained from each of these models are highly sensitive to changes in forward energy prices.

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To calculate the fair value of forward energy contracts, we typically 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. We obtain forward energy prices primarily from one pricing service that provides non-binding price information. The company is able to review the reliability of this pricing information through periodic participation in energy auctions. At March 31, 2012, our only significant unobservable input was related to forward energy prices, which ranged from $21 to $49 per MWh.

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-NE, 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.

Management has calculated the impact of an increase or decrease in forward energy prices as used in these models. If forward energy prices were increased or decreased in the models by 10 percent, this would increase or decrease, respectively, the fair value of total derivatives by $1.7 Million.

Level 3 Changes 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 at March 31 (dollars in thousands):

	Three months ended March 31
	2012			2011
Balance as of beginning of period	$	(4,936	)	$	28
Gains and losses (realized and unrealized)
Included in earnings		(163	)		(7	)
Included in Regulatory and other assets/liabilities		(4,004	)		60
Purchases		3			0
Net settlements		158			0
Balance at March 31, 2012	$	(8,942	)	$	81

At March 31, 2012 and 2011, 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 Sheet, 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 7 - 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 ratepayers 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. Regulatory authorities limit our ability to oversee the day-to-day management of our nuclear decommissioning trust fund investments and therefore we lack investing ability and decision-making authority. Accordingly, 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.

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In the first three months of 2012, we had minimal realized gains and losses. The realized losses include minimal impairments associated with our equity securities; however, there were no permanent impairments or ‘credit losses’ associated with our debt securities. There were also no non-credit loss impairments of our debt securities in the first three months of 2012.

In the first three months of 2011, we had minimal realized gains and losses. The realized losses include minimal impairments associated with our equity securities; however, there were no permanent impairments or ‘credit losses’ associated with our debt securities. In addition, there were no non-credit loss impairments to our debt securities in the first three months of 2011.

The fair values of these investments are summarized below (dollars in thousands):

	As of March 31, 2012
	Amortized Cost		Unrealized Gains		Unrealized Losses			Estimated Fair Value
Security Types	Amortized Cost		Unrealized Gains		Unrealized Losses			Estimated Fair Value
Marketable equity securities	$	3,107	$	1,762				$	4,869
Marketable debt securities
Corporate bonds		323		35					358
U.S. Government issued debt securities (Agency and Treasury)		929		74					1,003
State and municipal		59		2	$	(1	)		60
Other		30		2					32
Total marketable debt securities		1,341		113		(1	)		1,453
Cash equivalents and other		40							40
Total	$	4,488	$	1,875	$	(1	)	$	6,362

	As of December 31, 2011
	Amortized Cost		Unrealized Gains		Unrealized Losses			Estimated Fair Value
Security Types	Amortized Cost		Unrealized Gains		Unrealized Losses			Estimated Fair Value
Marketable equity securities	$	3,076	$	1,392				$	4,468
Marketable debt securities
Corporate bonds		329		28	$	(1	)		356
U.S. Government issued debt securities (Agency and Treasury)		884		79					963
State and municipal		87		2		(1	)		88
Other		29		1					30
Total marketable debt securities		1,329		110		(2	)		1,437
Cash equivalents and other		45							45
Total	$	4,450	$	1,502	$	(2	)	$	5,950

Information related to the fair value of debt securities at March 31, 2012 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	$	36	$	329	$	349	$	739	$	1,453

The fair value of debt securities in an unrealized loss position was $0.1 million at March 31, 2012 and December 31, 2011.

NOTE 8 – RESTRICTED CASH

The amount of restricted cash related to unreimbursed VEDA bond financing proceeds was $1.9 million at March 31, 2012 and $6.1 million at December 31, 2011. The investments consist primarily of commercial paper.

The VEDA bond proceeds are held in trust and we access these bond proceeds as reimbursement for capital expenditures made under certain production, transmission, distribution and general facility projects financed by the bond issue.

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As of March 31, 2012, we recorded $1.4 million of the restricted cash as a current asset on the Condensed Consolidated Balance Sheet representing costs paid that are expected to be reimbursed at the next requisition date. To date we have received reimbursements of $28.1 million. We expect to receive reimbursements of the remaining proceeds held in trust during 2012.

At March 31, 2012, we recorded $0.4 million of restricted cash as a current asset on the Condensed Consolidated Balance Sheet representing collateral under performance assurance requirements for certain of our power and transmission transactions.

In September 2011, we received $1.1 million from Omya for the repayment obligation for the five-year rate phase-in plan of the former Vermont Marble customers, as specified in the acquisition agreement between CV and Omya. As of March 31, 2012, $1 million was included in the current portion of restricted cash.

NOTE 9 - 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 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.

Alternative Regulation: On September 30, 2008, the PSB issued an order approving our alternative regulation plan. The plan became effective on November 1, 2008. It was scheduled to expire on December 31, 2011. The plan allows for quarterly PCAM adjustments to reflect changes in power supply and transmission-by-others costs and annual base rate adjustments to reflect changes in operating costs; and an annual ESAM adjustment to reflect changes, within predetermined limits, from the allowed earnings level. Under the plan, the allowed return on equity is 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 above 75 basis points is returned to customers in a future period. If the actual return on equity of our regulated business falls between 75 and 125 basis points below the allowed return on equity, the portion of the shortfall between 75 and 125 basis points is shared equally between shareholders and customers. Any earnings shortfall in excess of 125 basis points below the allowed return on equity is fully recovered from customers. As such, the minimum return for our regulated business is 100 basis points below the allowed return. These adjustments are made at the end of each fiscal year.

The ESAM also provides for an exogenous effects provision. Under this provision, we are allowed to defer, and collect from customers, the unexpected impact if in excess of $0.6 million, of changes in GAAP, tax laws, FERC or ISO-NE rules and major unplanned operation, maintenance costs, such as those due to major storms and other factors including loss of load not due to variations in heating and cooling temperatures. In 2011, we deferred $7.5 million of costs related to Tropical Storm Irene and legislative and tax law changes. We filed with the PSB on May 1, 2012 for recovery of these costs commencing on July 1, 2012 as provided by our alternative regulation plan.

By order dated March 3, 2011, the PSB approved amendments to the alternative regulation plan that: 1) extend its duration until December 31, 2013; 2) alter the methodology for implementing the non-power cost cap contained in the plan; 3) reset our allowed ROE for 2011 to 9.45 percent; and 4) remove provisions no longer applicable to the provision of our services.

Using the methodology specified in our alternative regulation plan, our 2011 return on equity from the regulated portion of our business is approximately 9.08 percent. We filed this calculation with the PSB on May 1, 2012. No additional ESAM adjustment was required since this return was within 75 basis points of our 2011 allowed return on equity of 9.45 percent.

The PCAM adjustment for the first quarter of 2012 was an over-collection of $0.8 million and was recorded as a current liability. This over-collection will be returned to customers over the three months ending September 30, 2012. We filed a PCAM report with the PSB identifying this over-collection. The PSB has not yet acted on this filing.

The PCAM adjustment for the fourth quarter of 2011 was an over-collection of $0.3 million and was recorded as a current liability. This over-collection will be returned to customers over the three months ending June 30, 2012. The DPS recommended the PCAM report be approved as filed and the PSB accepted the DPS recommendation and approved the filing.

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The PCAM adjustment for the third quarter of 2011 was an under-collection of $0.3 million and was recorded as a current asset. This under-collection was collected from customers over the three months ending March 31, 2012. The DPS recommended the PCAM report be approved as filed and the PSB accepted the DPS recommendation and approved the filing.

The PCAM adjustment for the first quarter of 2011 was an over-collection of $1 million and for the second quarter of 2011 was an over-collection of $0.8 million. These amounts were recorded as current liabilities and were returned to customers over the three months ending September 30, 2011 for first quarter and ending December 31, 2011 for the second quarter.

On November 1, 2011, we submitted a base rate filing for the rate year commencing January 1, 2012, as required by our alternative regulation plan. The filing proposed an increase in base rates of $15.8 million or a 4.78 percent increase in retail rates, reflecting an allowed ROE of 9.17 percent. Under our alternative regulation plan, the annual change in the non-power costs, as reflected in our base rate filing, is limited to any increase in the U.S. Consumer Price Index for the northeast, less a productivity adjustment that varies based upon the results of a comparison of certain cost metrics of the company with those of a benchmark group of U.S. electric utilities. For the 2012 rate year, the productivity adjustment was 0.95 percent. The non-power costs associated with the implementation of our Asset Management Plan and our CVPS SmartPower® project are excluded from the non-power cost cap. Our 2012 forecasted non-power costs did not exceed the non-power cost cap. On December 28, 2011, we received approval from the PSB and the 4.78 rate increase went into effect January 1, 2012.

Due to the pending merger, on April 13, 2012, we submitted a filing to the PSB requesting modifications to our existing alternative regulation plan. The proposed modifications include termination of our current plan as of September 30, 2012, except for residual ESAM adjustments and the power adjustor allowed under our current plan; termination of the currently effective base rate adjustments as of September 30, 2012; and adjustments to the timing and duration of the ESAM adjustments under the current plan to reflect the early termination of January 1, 2012 base rate change. The filing is expressly conditioned upon approval and closing of the Merger currently pending approval before the PSB. The submission was made as a part of the Memorandum of Understanding reached with Green Mountain Power Corporation and the Vermont Department of Public Service, which is also pending approval in the merger investigation.

CVPS SmartPower® 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.

On April 15, 2010, we signed an agreement with the DOE for our portion of the Smart Grid stimulus grant and project and the agreement became effective April 19, 2010. The agreement includes provisions for funding and other requirements. We are allowed to receive reimbursement of 50 percent of our total eligible project costs incurred since August 6, 2009, up to $31 million. From the inception of the project through March 31, 2012, we have incurred $15.8 million of costs, of which $8.4 million were operating expenses and $7.4 million were capital expenditures. We have submitted requests for reimbursement of $7.4 million and have received $6.8 million to date. We have received $1.8 million in reimbursements in 2012.

In the first quarter of 2012, we have incurred $2.2 million of costs, of which $0.8 million were operating expenses and $1.4 million were capital expenditures.

Pending Merger with Gaz Métro See Note 1 - Business Organization, Pending Merger with Gaz Métro, Regulatory approvals.

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Regulatory Accounting Under the 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 under accounting for regulated operations and there is not a rate mechanism to recover these costs, we would be required to write off $11.3 million of regulatory assets (total regulatory assets of $48.3 million less pension and postretirement medical costs of $37 million), $17.3 million of other deferred charges - regulatory and $4.3 million of other deferred credits - regulatory. This would result in a total charge to operations of $24.3 million on a pre-tax basis as of March 31, 2012. We would be required to record pre-tax pension and postretirement costs of $36.8 million to Accumulated Other Comprehensive Loss and $0.2 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).

	March 31, 2012		December 31, 2011
Regulatory Assets - Long-term Portion:
Pension and postretirement medical costs	$	36,817	$	37,300
Nuclear plant dismantling costs		3,454		3,827
Income taxes		4,702		4,722
Asset retirement obligations (a) (d)		418		426
Other (b) (d)		89		106
Total Regulatory Assets -Long-term Portion		45,480		46,381

Regulatory Assets - Current Portion:
Pension and postretirement medical costs (c) (d)		176		235
Nuclear refueling outage costs - Millstone Unit #3 (c) (d)		644		805
Nuclear plant dismantling costs (c) (d)		1,462		1,433
Environmental costs (c)		339		0
Asset retirement obligations and other (c) (d)		162		132
Total Regulatory Assets - Current Portion		2,783		2,605
Total Regulatory Assets	$	48,263	$	48,986

Other Deferred Charges - Regulatory - Long-term Portion:
ESAM deferred costs (b) (d)	$	1,880	$	3,759
FERC relicensing		609		609
Other (d)		254		255
Total Other Deferred Charges - Regulatory - Long-term Portion		2,743		4,623

Other Deferred Charges - Regulatory - Current Portion:
Unrealized loss on power-related derivatives (c)		8,955		4,940
ESAM deferred costs (c) (d)		5,639		3,759
Other (c) (d)		0		503
Total Other Deferred Charges - Regulatory - Current Portion		14,594		9,202
Total Other Deferred Charges - Regulatory	$	17,337	$	13,825

Other Deferred Credits - Regulatory - Long-term Portion:
Asset retirement obligation - Millstone Unit #3	$	3,430	$	3,060
Other (c) (d)		21		21
Total Other Deferred Credits - Regulatory - Long-term Portion:		3,451		3,081

Other Deferred Credits - Regulatory - Current Portion:
CVPS SmartPower® grant reimbursements (c) (d)		167		222
Other (c) (d)		649		825
Total Other Deferred Credits - Regulatory - Current Portion		816		1,047
Total Other Deferred Credits - Regulatory	$	4,267	$	4,128

(a)	Remaining recovery period is 14 years

(b)	Remaining recovery period is 2 years

(c)	Remaining recovery period is 1 year

(d)	Currently earning a return

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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. 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 12 - 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 4 - Investments in Affiliates. Power-related derivatives are discussed in more detail in Note 6 - Fair Value.

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. Throughout most of 2011 and early 2012, before our Vermont Yankee contract expired, our power supply forecast showed energy purchase and production amounts in excess of our load requirements. Because of this surplus, we entered into one forward power sale contract that settled financially for all of 2011. In the fourth quarter of 2011, we entered into a similar rate swap for the sale of excess power in January and February 2012. Neither the 2011 or 2012 rate swaps were derivatives, since a notional amount did not exist under the terms of either contract.

The company regularly monitors forecasts of available power supply and retail customer load, and attempts to balance our power supply portfolio with expected load requirements. If we forecast power supply shortages, we will typically enter into either short-term or long-term forward power purchase contracts to cover the expected power supply shortages, which helps reduce price volatility in our net power costs. In July 2011, we entered into two contracts to fill what would have been power supply shortages expected between April and December 2012 due to the expiration of our long-term contract with Vermont Yankee in March 2012.

In September 2011, in connection with the Vermont Marble acquisition, we assumed two forward purchase contracts. The Vermont Marble contracts provide for nominal deliveries of physical power between September 2011 and December 2012, and we determined that these purchase contracts are derivatives.

We have determined that the power purchase contracts we entered into for 2012 are derivatives. We did not elect the “normal purchase, normal sale” exception for any of these short-term power purchase contracts.

On August 12, 2010, we executed a significant long-term power purchase contract with HQUS and we have concluded that this contract meets the “normal purchase, normal sale” exception to derivatives accounting; therefore, we are not required to calculate the fair value of this contract. For additional information on this contract, see Note 13 - Commitments and Contingencies.

In 2009, we also elected the “normal purchase, normal sale” exception for a three-year forward purchase contract that begins in 2013.

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-NE.

We do not use derivative financial instruments for trading or other purposes. Accounting for power-related derivatives is discussed in Note 2- Summary of Significant Accounting Policies.

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Outstanding power-related derivative contracts are as follows:

	MWh (000s)
	March 31, 2012		December 31, 2011
Commodity
Forward Energy Purchase Contracts		530.9		535.3
Financial Transmission Rights		212.7		326.9

We recognized the following amounts in the Condensed Consolidated Statements of Income in connection with derivative financial instruments for the three months ended March 31 (dollars in thousands):

	2012			2011
Net realized gains (losses) reported in operating revenues	$	0		$	0
Net realized gains (losses) reported in purchased power		(163	)		(7	)
Net realized gains (losses) reported in earnings	$	(163	)	$	(7	)

Realized gains and losses on derivative instruments are conveyed to or recovered from customers through the PCAM and have no net impact on results of operations. Derivative transactions and related collateral requirements are included in net cash flows from operating activities in the Consolidated Statements of Cash Flows. For information on the location and amounts of derivative fair values on the Consolidated Balance Sheets see Note 6 - Fair Value.

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. The aggregate fair value of all derivative instruments with credit-risk related contingent features that were in a liability position at March 31, 2012 was $6.8 million, for which we were not required to post collateral since our issuer credit rating from Moody’s is Baa3. If Moody’s were to lower our issuer credit rating to Ba1, we would be required to post $6.3 million of collateral with our counterparties, upon their request. If our Moody’s credit rating were further lowered to Ba2, our counterparties could request an additional $0.5 million of collateral. For information concerning performance assurance, see Note 13 - Commitments and Contingencies.

NOTE 11 - LONG-TERM DEBT AND NOTES PAYABLE

Credit Facility: We have a three-year, $40 million unsecured revolving credit facility with a lending institution pursuant to a Credit Agreement dated October 25, 2011 that expires on October 24, 2014. This facility replaced a three-year, $40 million unsecured revolving credit facility that matured on November 2, 2011. The Credit Agreement contains financial and non-financial covenants. 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 March 31, 2012, there were $0.1 million in loans and $3.5 million in letters of credit outstanding under the credit facility. At December 31, 2011, there were $12.3 million in loans and $3.5 million in letters of credit outstanding under the credit facility.

NOTE 12 - PENSION AND POSTRETIREMENT MEDICAL BENEFITS

The fair value of Pension Plan trust assets was $111.4 million at March 31, 2012 and $107.7 million at December 31, 2011. The unfunded accrued pension benefit obligation recorded on the Condensed Consolidated Balance Sheets was $32.3 million at March 31, 2012 and $31.3 million at December 31, 2011.

The fair value of Postretirement Plan trust assets was $20.2 million at March 31, 2012 and $18.6 million at December 31, 2011. The unfunded accrued postretirement benefit obligation recorded on the Condensed Consolidated Balance Sheets was $7 million at March 31, 2012, and 6.8 million at December 31, 2011.

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Components of net periodic benefit costs for the three months ended March 31 were as follows (dollars in thousands):

	Pension Benefits						Postretirement Benefits
	2012			2011			2012			2011
Service cost	$	1,246		$	1,142		$	190		$	198
Interest cost		1,780			1,851			307			330
Expected return on plan assets		(1,993	)		(2,120	)		(334	)		(357	)
Amortization of transition obligation		0			0			48			64
Amortization of prior service cost		82			104			70			70
Amortization of net actuarial loss		227			60			56			51
Net periodic benefit cost		1,342			1,037			337			356
Less amounts capitalized		267			212			67			73
Net benefit costs expensed	$	1,075		$	825		$	270		$	283

NOTE 13 - COMMITMENTS AND CONTINGENCIES

Long-Term Power Purchases Vermont Yankee PPA: We purchased our entitlement share of Vermont Yankee plant output through the VY PPA between Entergy-Vermont Yankee and VYNPC until our contract expired on March 21, 2012. Our total VYNPC purchases for the first three month ended March 31, 2012 were $15.2 million and $17.1 million for the three months ended March 31, 2011.

Vermont Yankee – Cooling Towers: On June 22, 2010, we, along with GMP, made a claim to Entergy-Vermont Yankee under the September 6, 2001 VY PPA. The parties claim that Entergy-Vermont Yankee breached its obligations under the agreement by failing to detect and remedy the conditions that resulted in cooling tower-related failures at the Vermont Yankee nuclear plant in 2007 and 2008. Those failures caused us and GMP to incur substantial incremental replacement power costs.

We are seeking recovery of the incremental costs from Entergy-Vermont Yankee under the terms of the VY 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 also reviewed the 2007 and 2008 root cause analysis reports by Entergy-Vermont Yankee and a December 22, 2008 reliability assessment provided by Nuclear Safety Associates to the State of Vermont. Entergy-Vermont Yankee disputes our claim.

On January 10, 2012, after failing to reach a resolution of the matter with Entergy-Vermont Yankee, we and GMP filed a lawsuit in Vermont Superior Court in Windham County. The lawsuit seeks compensatory damages of $6.6 million to cover increased power costs and lost capacity payments resulting from the tower failures, plus interest. Our portion of this claim is $4.3 million. On January 18, 2012, Entergy-Vermont Yankee filed a notice of removal of the case to the United States District Court for the District of Vermont, asserting diversity of citizenship and federal jurisdiction over a federal question. Entergy-Vermont Yankee also filed an answer to the complaint, and asserted affirmative defenses and demanded a jury trial. A scheduling order has been issued, and the parties are engaged in discovery. The case is now pending in the federal court. We cannot predict the outcome of this matter at this time.

Vermont Yankee – License Renewal: On January 19, 2012 the U.S. District Court for the District of Vermont issued a decision ruling against the state of Vermont. The effect of the ruling is that the state is prohibited under federal law from taking any action to compel the plant to shut down after March 21, 2012 because it failed to obtain legislative approval (under the provisions of Act 160). The state of Vermont was precluded from shutting the plant down for safety-related reasons. On February 18, 2012, the state filed a notice of appeal with the 2nd U.S. Circuit Court of Appeals in New York. Meanwhile, Vermont Yankee still must obtain a Certificate of Public Good from the PSB to gain a 20-year license extension. We are participants in this docket due to a prior revenue-sharing agreement. That revenue-sharing arrangement provides in part that in the event that Entergy extends the operation of the plant pursuant to an extension of its NRC license, Entergy agrees to share with VYNPC 50 percent of the “Excess Revenue” for 10 years commencing on March 13, 2012.

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On February 27, 2012, Entergy filed notice with the U.S. District Court for the District of Vermont saying that it would ask the 2nd U.S. Circuit Court of Appeals to review a decision. It will appeal a federal judge’s order allowing the plant to stay open past its originally scheduled shutdown date, and will ask the original judge to revisit his order and prevent the state of Vermont from barring the future storage of spent nuclear fuel at the plant. Entergy has informed the PSB that it intends to continue to operate the plant pending a final PSB ruling on its operation. On March 19, 2012, the U.S. District Court issued an order barring the Vermont state defendants from taking action to enforce a certain Vermont statute that would compel Vermont Yankee to shut down because the “cumulative total amount of spent fuel stored at Vermont Yankee” exceeds “the amount derived from the operation of the facility up to, but not beyond, March 21, 2012.”

On March 29, 2012, the PSB denied Entergy’s motion for the immediate issuance of the Certificate of Public Good and ordered Entergy to file an amended petition that identifies the specific approval or approvals that it is seeking from the Board, and the state-law authority under which the Board would issue each approval that Entergy VY seeks. Entergy filed its petition for a CPG on April 16, 2012 and a new docket has been opened to consider Entergy VY's amended petition.

Hydro-Québec: We continue to purchase power under the Hydro-Québec 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-Québec, altering the terms and conditions contained in the original contract by reducing the overall power requirements and related costs. The VJO power contract runs through 2020, but our purchases under the contract end in 2016. The average level of deliveries under the current contract decreases by approximately 20 percent after 2012, and by approximately 84 percent after 2015. Total purchases under the VJO power contract were $16.8 million for the three months ended March 31, 2012 and $16.5 million for the three months ended March 31, 2011.

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 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 31, 2012.

A second sellback contract provided benefits to us that ended in 1996 in exchange for two options to Hydro-Québec. The first option was never exercised and expired December 31, 2010. The second gives Hydro-Québec 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 Québec. This second option can be exercised five times through October 2015 but due to the notice provision there is a maximum remaining application of two times available. To date, Hydro-Québec has not exercised this option. We have determined that this second option is not a derivative because it is contingent upon a physical variable.

There are specific contractual provisions providing that in the event any VJO member fails to meet its obligation under the contract with Hydro-Québec, the remaining VJO participants will “step-up” to the defaulting party’s share on a pro-rata basis. As of March 31, 2012, our obligation is about 47 percent of the total VJO power contract through 2016, and represents approximately $208.7 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 $247 million for the remainder of the contract, assuming that all members of the VJO defaulted by April 1, 2012 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.

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Independent Power Producers: We receive power from several IPPs, primarily so-called small power producers. These plants use water or biomass as fuel. Starting in 2012, we will also purchase power from some larger independent producers, primarily wind projects. Total purchases from IPPs were $6.4 million for the three months ended March 31, 2012 and $6.3 million for the three months ended March 31, 2011.

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 Millstone Unit #3 decommissioning costs. 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 there is a need for additional decommissioning funding, 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 4 - 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.

DOE Litigation We have a 1.7303 joint-ownership percentage in Millstone Unit #3, in which 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 can 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 replied to the government’s brief in August, 2010. The government’s reply brief was filed September 14, 2010 and briefing on the appeal is now complete. Oral argument on the government’s appeal occurred before the Federal Circuit on January 12, 2011.

On April 25, 2011 the U.S. Court of Appeals for the Federal Circuit issued a decision affirming the spent fuel damages award for damages incurred through June 30, 2006 in connection with DOE’s failure to begin accepting spent fuel for disposal. The government had the option to seek rehearing of the Federal Circuit decision and to seek review by the U.S. Supreme Court. The time period for seeking rehearing was 45 days.

On June 30, 2011, DNC informed us that the DOE decided not to seek rehearing and instead wishes to pay the awarded damages. In October 2011 we received $0.2 million and the amount was credited to our retail customers.

Also, see Note 4 – Investments in affiliates for additional DOE litigation proceedings.

Future Power Agreements New Hydro-QuébecAgreement: On August 12, 2010 we, along with GMP, VPPSA, Vermont Electric Cooperative, Inc., Vermont Marble, Town of Stowe Electric Department, City of Burlington, Vermont Electric Department, Washington Electric Cooperative, Inc. and the 13 municipal members of VPPSA (collectively, the “Buyers”) entered into an agreement for the purchase of shares of 218 MW to 225 MW of energy and environmental attributes from HQUS commencing on November 1, 2012 and continuing through 2038. The HQUS PPA will replace approximately 65 percent of the existing VJO power contract discussed above.

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The rights and obligations of the Buyers under the HQUS PPA, including payment of the contract price and indemnification obligations, are several and not joint or joint and several. Therefore, we shall have no responsibility for the obligations, financial or otherwise, of any other party to the HQUS PPA. The parties have also entered into related agreements, including collateral agreements between each Buyer and HQUS, a Hydro-Québec guaranty, an allocation agreement among the Buyers, and an assignment and assumption agreement between us and Vermont Marble, related to the acquisition.

On August 17, 2010, the Buyers filed a petition with the PSB asking for Certificates of Public Good under Section 248 of Title 30, Vermont Statutes Annotated. On April 15, 2011, the PSB issued an order approving the HQUS PPA.

Under the HQUS PPA, we are entitled to purchase an energy quantity of up to 5 MW from November 1, 2012 to October 31, 2015; 90.4 MW from November 1, 2015 to October 31, 2016; 101.4 MW from November 1, 2016 to October 31, 2020; 103.4 MW from November 1, 2020 to October 31, 2030; 112.8 MW from November 1, 2030 to October 31, 2035; and 27.4 MW from November 1, 2035 to October 31, 2038. These quantities include assumption of Vermont Marble’s allocations as a result of our September 1, 2011 purchase of Vermont Marble.

Other Future Power Agreements: As we continue to build and diversify our power portfolio as planned and to comply with state law which establishes goals for including renewable power in our mix, we have signed several agreements for clean and competitively priced renewable energy. On September 9, 2010 we agreed to terms for purchasing output over nine years from Iberdrola Renewables’ planned Deerfield Wind Project. The agreement was signed by the parties on December 13, 2010. Due to delays in receiving a necessary permit from the U.S. Forest Service, construction is not now scheduled to take place in a manner that would be sufficient for meeting the conditions precedent of the agreement and the project is now on hold. Conditions precedent not satisfied or waived on or before April 1, 2012 could result in termination of the contract by June 30, 2012. We are currently in discussions with Iberdrola, the parent company, with respect to terminating, reforming or replacing the agreement.

Other agreements signed in 2010 include: two separate agreements to purchase 30.3 percent of the actual output from Granite Reliable Wind project for 20 years beginning April 1, 2012 and an additional 20 percent for 15 years beginning in November 2012; an agreement to purchase the entire 4.99 MW output of Ampersand Gilman Hydro for five years starting April 1, 2012; and 15 MW of around-the-clock energy from J.P. Morgan Ventures Energy for the calendar years 2013 through 2015.

On July 27, 2011, in cooperation with an energy management firm, we conducted a highly structured Internet auction that involved a dozen pre-screened northeastern generators and energy marketers. When the bidding closed, we signed three contracts with an average price of approximately $47.50 per megawatt-hour, or 4.75 cents per kilowatt-hour.

Two of the contracts will fill the 2012 gap in our portfolio created by the end of the VY PPA. One will supply energy 24 hours per day from April 1, 2012 through the end of the year, while the other will provide both peak and off-peak power during specific periods in 2012 when we have remaining supply gaps. The third contract filled our energy needs during the planned Vermont Yankee refueling outage that ended November 3, 2011.

These purchase contracts will provide about 570,000 megawatt-hours of energy or about 20 percent of our power supply during the life of the contracts, for $27 million. The contracts are for so-called “system power,” meaning they are not conditioned on the operation of individual power generation sources.

In September 2011, we also used the auction process to sell small amounts of projected excess energy to hedge price risks during the first two months of 2012.

Performance Assurance We are subject to performance assurance requirements through ISO-NE under the Financial Assurance Policy for NEPOOL members. At our current investment-grade credit rating, we have a credit limit of $3 million with ISO-NE. We are required to post collateral for all net power and transmission transactions in excess of this credit limit. Additionally, we purchase 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 March 31, 2012, we had posted $4.1 million of collateral under performance assurance requirements for certain of our power and transmission transactions, $3.5 million of which was represented by a letter of credit and $0.6 million of which was represented by cash and cash equivalents. At December 31, 2011, we had posted $3.9 million of collateral under performance assurance requirements for certain of our power and transmission transactions, $3.5 million of which was represented by a letter of credit and $0.4 million of which was represented by cash and cash equivalents.

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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 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 $0.3 million as of March 31, 2012 and December 31, 2011. The reserve for environmental matters is included in current 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.

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, although it reserved the right to require further investigation or remedial measures. In 2002, the VANR notified us that our corrective action plan for the site was approved. As of March 31, 2012, our estimate of the remaining obligation is $0.3 million.

The Windham Regional Commission and the Town of Brattleboro are currently 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 met with the Town of Brattleboro in 2011 and we agreed to an Amended and Restated Grant of Environmental Restrictions for the gas plant property. In November 2011, we contributed $0.2 million toward the remediation project, which will likely satisfy our obligation at this site. We will maintain a reserve until a corrective action plan has been implemented and green space has been constructed. Construction began in early 2012 and should be completed during the 2012 construction season.

Salisbury Substation: We completed internal testing and found PCBs and TPH, in addition to small quantities of pesticides in the soil and concrete at this substation. The substation is located adjacent to the Salisbury hydroelectric power station and both facilities underwent modernization projects in late 2011 and early 2012. Test results indicated that PCB, TPH and pesticide concentrations exceed state and federal regulatory limits in portions of the substation. In late 2011 and early 2012, we removed the contaminated material from the substation in accordance with VANR and EPA-approved remediation plans. The work consisted of excavation and removal of soil and concrete and there was more contaminated material than estimated. The site work is complete and we will submit the requisite summary reports to the VANR and EPA early in the second quarter of 2012. As of March 31, 2012, our estimate of the remaining obligation is less than $0.1 million.

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. Under the terms of the agreements with Catamount and Diamond Castle Holdings, 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. To management’s knowledge, there is no pending or threatened litigation with the potential to cause material expense. No government agency has sought funds from us for any study or remediation.

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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 March 31, 2012 is approximately $0.3 million. The total future minimum lease payments required for all lease schedules under this agreement at March 31, 2012 is $2.0 million. As of March 31, 2012 there is no credit line in place for additions under this agreement. The total acquisition cost of all lease additions under this agreement at March 31, 2012 was $4.1 million.

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 March 31, 2012 is $1.6 million. As of March 31, 2012 there is no credit line in place for additions under this agreement. The total acquisition cost of all lease additions under this agreement at March 31, 2012 was $2.9 million.

Legal Proceedings We are involved in legal and administrative proceedings, including civil litigation, in the normal course of business as well as a number of lawsuits relating to our pending merger agreement with Gaz Métro that are described in Note 1 – Business Organization, Litigation Related to Merger Agreement. We are unable to fully determine a range of reasonably possible court-ordered damages, settlement amounts, and related litigation costs or legal liabilities that would be in excess of amounts accrued and amounts covered by insurance. Based on the information currently available, we do not believe that it is probable that any such legal liability will have a material impact on our consolidated financial position. It is reasonably possible that additional legal liabilities that may result from changes in estimates could have a material impact on our results of operations, financial condition or cash flows.

NOTE 14- SEGMENT REPORTING

Our reportable operating segments include: Central Vermont Public Service Corporation (“CV - VT”), represents our principal utility operations, which engages in the purchase, production, transmission, distribution and sale of electricity in Vermont. East Barnet is included with CV- VT in the table below. Other Companies represents our non-utility operations and consists of CRC, and C.V. Realty, Inc. CRC was formed to hold our subsidiaries that invest in unregulated business opportunities and is the parent company of SmartEnergy Water Heating Services, Inc., which engages in the sale and rental of electric water heaters in Vermont and New Hampshire. C.V. Realty, Inc. is a real estate company whose purpose is to own, acquire, buy, sell and lease real and personal property and interests.

The accounting policies of operating segments are the same as those described in Note 2 - Summary of Significant Accounting Policies. All segment operations are managed centrally by CV - VT. Segment profit or loss is based on net income. Other Companies are below the quantitative thresholds individually and in the aggregate.

	CV-VT		Unregulated Companies		Reclassification & Consolidating Entries			Consolidated
March 31, 2012
Revenues from external customers	$	96,242	$	418	$	(418	)	$	96,242
Net income	$	8,855	$	20				$	8,875
Total assets at March 31, 2012	$	771,834	$	3,000	$	(204	)	$	774,630

March 31, 2011
Revenues from external customers	$	97,085	$	423	$	(423	)	$	97,085
Net income	$	8,358	$	67				$	8,425
Total assets at December 31, 2011	$	773,557	$	2,949	$	(241	)	$	776,265

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

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

our ability to meet the requirements under the Merger Agreement with Gaz Métro;

the actions of regulatory bodies with respect to our pending Merger with Gaz Métro, allowed rates of return, continued recovery of regulatory assets and alternative regulation;

liquidity requirements;

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-NE;

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, state entities 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 Part I, Item 1A, Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2011.

EXECUTIVE SUMMARY

The results of our operations for the three months ended March 31, 2012 were earnings of $8.9 million, or 65 cents per diluted share of common stock. Excluding merger-related expenses of $0.3 million after-tax, or $0.02 per diluted share of common stock, the results of our operations for the three months ended March 31, 2012 were earnings of $9.2 million, or $0.67 per diluted share of common stock. This compares to 2011 earnings of $8.4 million, or 62 cents per diluted share of common stock.

The following is a reconciliation of 2012 net earnings, excluding merger-related costs:

	2012
	Net Income			Earnings Per Diluted Share

	(in millions)
Net earnings excluding merger-related expenses	$	9.2		$	0.67
Merger-related expenses, after-tax		(0.3	)		(0.02	)
Net earnings	$	8.9		$	0.65

The primary drivers of the year-over-year earnings variances are described in Results of Operations below.

Pending merger-related costs: In 2012, we incurred $0.5 million in pre-tax merger-related costs, or $0.02 after-tax per diluted share of common stock. These costs are components of Other operations, within Operating Expenses and Other Income on the Consolidated Statements of Income.

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We discuss the pending Merger with Gaz Métro, our financial initiatives and our key business risks in more detail below.

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 for long-term power contracts that have expired; and evaluating opportunities to further invest in Transco. Continued focus on these financial initiatives is critical to maintaining our corporate credit rating.

PENDING MERGER

Pending Merger with Métro On July 11, 2011, CVPS, Gaz Métro Limited Partnership (“Gaz Métro”) and Danaus Vermont Corp., an indirect wholly owned subsidiary of Gaz Métro (“Merger Sub”), entered into an Agreement and Plan of Merger (the “Merger Agreement”).

Upon the terms and subject to the conditions set forth in the Merger Agreement, unanimously approved by the boards of directors of CVPS and Gaz Métro Inc., the general partner of Gaz Métro , Merger Sub will merge with and into CVPS (the “Merger”), with CVPS continuing as the surviving corporation and an indirect wholly owned subsidiary of Gaz Métro .

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In addition, we made other regulatory filings seeking approval of the Merger, including with the NRC, the FERC, the Federal Trade Commission, Federal Communications Commission, the Committee on Foreign Investments in the U.S., New York State Public Service Commission, New Hampshire Public Utilities Commission, and the Maine Public Utility Commission. On September 26, 2011, in connection with the Hart Scott-Rodino filing, the Federal Trade Commission granted early termination of the statutory waiting period, which effectively allows us to continue planning for the Merger. On November 22, 2011 we received approvals from the Committee on Foreign Investments in the U.S. and the Maine Public Utility Commission. Also, on November 22, 2011 the New York State Public Service Commission issued a declaratory ruling of no jurisdiction. On March 6, 2012, we received approval from the FERC and on March 7, 2012, we received approval from the Federal Communications Commission for the transfer of control of our radio licenses.

On July 11, 2011, prior to entering into the Merger Agreement with Gaz Métro, CVPS terminated the Fortis Merger Agreement. In accordance with the Fortis Merger Agreement, on July 12, 2011, CVPS paid FortisUS Inc. $19.5 million (the “Fortis Termination Payment”), consisting of a termination fee of $17.5 million and expenses of FortisUS Inc. of $2 million. These amounts have been recorded as a component of Other Income on the Consolidated Statement of Income in 2011. The Merger Agreement with Gaz Métro required Gaz Métro to reimburse CVPS for its payment of the Fortis Termination Payment immediately following the approval of the Merger Agreement by CVPS shareholders. It also provides that CVPS will be required to pay Gaz Métro the full amount of the Fortis Termination Payment reimbursement if the Merger Agreement is terminated under certain circumstances.

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RETAIL RATES AND ALTERNATIVE REGULATION

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Due to the pending merger, on April 13, 2012, we submitted a filing to the PSB requesting modifications to our existing alternative regulation plan. The proposed modifications include termination of our current plan as of September 30, 2012, except for residual ESAM adjustments and the power adjustor allowed under our current plan; termination of the currently effective base rate adjustments as of September 30, 2012; and adjustments to the timing and duration of the ESAM adjustments under the current plan to reflect the early termination of our current plan January 1, 2012 base rate change. The filing is expressly conditioned upon approval of the merger with Danaus Vermont Corp. currently pending approval before the PSB. The submission was made as a part of the Memorandum of Understanding reached with Green Mountain Power Corporation and the Vermont Department of Public Service, which is also pending approval in the merger investigation.

In the first quarter of 2012, we have incurred $2.2 million of costs, of which $0.8 million were operating expenses and $1.4 million were capital expenditures.

Pending Merger with Gaz Métro See Note 1 - Business Organization, Pending Merger with Gaz Métro, Regulatory approvals.

LIQUIDITY, CAPITAL RESOURCES AND COMMITMENTS

Cash Flows At March 31, 2012, we had cash and cash equivalents of $1.7 million, compared to $15.1 million at March 31, 2011.

Our primary sources of cash for the three months ended March 31, 2012 were from our electric utility operations, distributions received from affiliates, income tax refunds, reimbursements from restricted cash of debt-financed project costs and borrowings under our revolving credit facility. Our primary uses of cash for the three months ended March 31, 2012 included capital expenditures, common and preferred stock dividend payments, repayments of borrowings under our revolving credit facility, and working capital requirements.

Operating Activities: Operating activities provided $18.2 million in 2012, compared to $32.4 million in 2011. The decrease of $14.2 million was primarily due to: an $8 million decrease in net income tax refunds; a $1.1 million recovery of bad debt expense in 2011; $0.5 million used for merger-related costs in 2012 versus none in 2011; and a $6 million decrease in working capital and other operating activities. This was partially offset by a $1.4 million increase in distributions received from affiliates.

At March 31, 2012, our retail customers’ accounts receivable over 60 days totaled $3.6 million compared to $3.4 million at December 31, 2011, which was an increase of 5.4 percent.

Investing Activities: Investing activities used $5 million in 2012, compared to $2.8 million in 2011. The increase of $2.2 million used is due to: a $2.9 million decrease in reimbursements of restricted cash from bond proceeds and $0.4 million of various other investing activities. These items were partially offset by a $0.7 million increase in project reimbursements from the DOE and $0.4 million of lower construction and plant expenditures. The majority of the construction and plant expenditures were for system reliability, performance improvements and customer service enhancements.

Financing Activities: Financing activities used $13.2 million in 2012, compared to $17.1 million in 2011. The decrease of $3.9 million is due to: a $1.6 million decrease in net credit facility repayments; a $1.4 million increase in net proceeds from the issuance of common stock; and a $0.9 million increase from various other financing activities.

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Transco Based on current projections, Transco expects to need additional equity capital periodically beginning in 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 are currently considering additional investments of approximately $21 million in 2012, no investment in 2013, $14 million in 2014, $24 million in 2015 and $7 million in 2016, but the timing and amounts depend on the factors discussed above and the amounts invested by other owners.

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.

Preferred Stock In accordance with the terms of the Merger Agreement, we plan to redeem all outstanding shares of our preferred stock in June 2012, prior to the closing of the Merger with Gaz Métro, pursuant to the terms of such preferred stock.

Dividends Our dividend level is reviewed by our Board of Directors on a quarterly basis. It is our goal to ensure earnings are sufficient to maintain our current dividend level until we close the merger with Gaz Métro. The Merger Agreement permits us to continue paying our regular quarterly dividend of 23 cents per common share after November 20, 2011, if so declared by the Board of Directors.

Cash Flow Risks Based on our current cash forecasts, we will require outside capital in addition to cash flow from operations and our unsecured revolving credit facilities to fund our business over the next few years. Upheaval in the global 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 power supply 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-NE or third parties. However, this risk has decreased because the New England market has a significant surplus of available energy, due to the significant reductions in natural gas prices, and electrical energy is available at competitive rates. The PCAM within our alternative regulation plan allows recovery of power costs; therefore, in general, power costs 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; significant storm recovery costs; required prepayments for power purchases; and increases in performance assurance requirements. It is important to note, however, that our alternative regulation plan allows for recovery of costs related to exogenous events such as significant storm damage and, additionally, sets bands around the earnings in our regulated business, which ensures, in part, that they will not fall below prescribed levels relative to our allowed ROE. 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. We also have a shelf facility directly with a potential bond purchaser under which we can issue up to $60 million of additional first mortgage bonds to them, though they have no obligation to purchase such bonds. 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.

Financing Credit Facility: We have a three-year, $40 million unsecured revolving credit facility with a lending institution pursuant to a Credit Agreement dated October 25, 2011 that expires on October 24, 2014. This facility replaced a three-year, $40 million unsecured revolving credit facility that matured on November 2, 2011. The Credit Agreement contains financial and non-financial covenants. 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 March 31, 2012, $3.5 million in letters of credit and $0.1 million in borrowings were outstanding under this credit facility.

We also have a three-year, $15 million unsecured revolving credit facility with a different lending institution pursuant to a Credit Agreement dated December 22, 2010 that expires in December 2013. The purpose and obligation under this credit agreement are the same as described above. We did not use this facility for borrowings or letters of credit during 2012 or 2011.

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Letters of credit: We have two outstanding unsecured letters of credit, issued by one bank, that support the CDA and VIDA revenue bonds. These letters of credit total $11.1 million in support of the two revenue bond issues totaling $10.8 million, discussed above. We pay an annual fee of 2.4 percent on the letters of credit. These letters of credit expire on November 30, 2012. The letters of credit contain cross-default provisions to our wholly owned subsidiaries. These cross-default provisions generally relate to an inability to pay debt or debt acceleration, the levy of significant judgments or insolvency. At March 31, 2012, there were no amounts drawn under these letters of credit.

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 March 31, 2012, 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.

Capital Commitments Our business is capital-intensive because annual construction expenditures are required to maintain the distribution system and our production units. As of March 31, 2012, capital expenditures were $9.6 million.

Capital expenditures for the years 2012 to 2014 are expected to range from $42 million to $69 million annually, including an estimated total of more than $25.5 million for CVPS SmartPower® over the three-year period. A portion of the CVPS SmartPower® project will be funded by the Smart Grid Stimulus Grant and this grant has reduced the estimated spending range above. Further discussion of the Smart Grid Stimulus Grant can be found above in Retail Rates and Alternative Regulation - CVPS SmartPower®.

Future Liquidity Needs In order to meet our expected levels of capital expenditures and investments in affiliates we expect to need outside capital over the next few years. If the pending merger with Gaz Métro is delayed or is not ultimately consummated, we expect to issue additional debt and equity in 2012.

Off-balance-sheet arrangements We do not use off-balance-sheet arrangements, such as securitization of receivables, nor do we obtain access to assets through special purpose entities. We have $11.1 million of unsecured letters of credit related to our CDA and VIDA revenue bonds and a $3.5 million letter of credit issued under our $40 million unsecured revolving credit facility. We also have outstanding a $30 million issue of first mortgage bonds, Series VV as security for the $30 million VEDA bonds.

Commitments and Contingencies Power Supply Matters: We have material power supply commitments for the purchase of power from VYNPC through March 21, 2012 and Hydro-Québec. 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. 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 4 - Investments in Affiliates.

Environmental Matters: We are subject to extensive federal, state and local environmental regulations that monitor, among other things, emission allowances, pollution controls, maintenance and upgrading of facilities, site remediation, equipment upgrades and management of hazardous waste. We believe that we are materially in compliance with all applicable environmental and safety laws and regulations; however, there can be no assurance that we will not incur significant costs and liabilities in the future. See Note 13 – Commitments and Contingencies.

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On December 20, 2005, we completed the sale of Catamount, our wholly owned subsidiary, to CEC Wind Acquisition, LLC, a company established by Diamond CastleHoldings, a New York-based private equity investment firm. Under the terms of the agreements with Catamount and Diamond Castle Holdings, we agreed toindemnify them, and certain of their respective affiliates as described in Note 13 - Commitments and Contingencies.

Legal Proceedings: We are involved in legal and administrative proceedings, including civil litigation, in the normal course of business as well as a number of lawsuits relating to our pending merger agreement with Gaz Métro that are described above in Pending Merger, Litigation Related to Merger Agreement. We are unable to fully determine a range of reasonably possible court-ordered damages, settlement amounts, and related litigation costs or legal liabilities that would be in excess of amounts accrued and amounts covered by insurance. Based on the information currently available, we do not believe that it is probable that any such legal liability will have a material impact on our consolidated financial position. It is reasonably possible that additional legal liabilities that may result from changes in estimates could have a material impact on our results of operations, financial condition or cash flows. See Note 1 – Business Organization, Litigation Related to Merger Agreement, for discussion of pending litigation related to the merger.

OTHER BUSINESS RISKS

Our 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 occurrence.

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 statement of operations 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 below.

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.

Power Supply Risk: The New England Market currently has a significant surplus of available energy and generating capacity, and due to significant reductions in natural gas prices, electrical energy is available at competitive rates.

Hydro-Québec contract deliveries through our current contract end in 2016, with the average level of deliveries decreasing by approximately 20 percent after 2012, and by approximately 84 percent after 2015. In August 2010, we signed a new contract for ongoing Hydro-Québec supplies and it was approved by the PSB in April 2011.

We continue to seek out other power sources but there is a risk that future sources available may not be as reliable and the price of such replacement power could be significantly higher than what we have in place today. However, we have 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. See Power Supply Matters, below.

Wholesale Power Market Price Risk: The majority of our future MWh purchases are through contracts with Hydro-Québec. If this source becomes unavailable for a period of time, there could be exposure to more volatile wholesale power prices and that amount could be material. See Cash Flow Risks above.

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. The PCAM within our alternative regulation plan allows recovery of power costs.

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

RESULTS OF OPERATIONS

The following is a detailed discussion of the results of operations for the three months ended March 31, 2012. This should be read in conjunction with the Condensed Consolidated Financial Statements and accompanying notes included in this report.

Our consolidated earnings for the three months ended March 31, 2012 were $8.9 million, or 65 cents per diluted share of common stock. This compares to $8.4 million, or 62 cents per diluted share of common stock for the three months ended March 31, 2011.

The tables that follow provide a reconciliation of the primary year-over-year variances in diluted earnings per share the three months ended March 31, 2012 and 2011. The earnings per diluted share for each variance shown below are non-GAAP measures:

Reconciliation of Earnings Per Diluted Share
	Three Months 2012 vs. 2011
2011 Earnings per diluted share	$	0.62

Major Year-over Year Effects on Earnings:
Lower service restoration due to no major storms in 2012		0.02
Lower salaries expense		0.02
Variable life insurance		0.02
Lower retail revenue sales volume due to weather		(0.03	)
Merger-related fees		(0.02	)
Other (includes income tax adjustments, and various items)		0.02
2012 Earnings per diluted share	$	0.65

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 for the three months ended March 31are summarized below.

	Three months ended March 31
	Revenues (in thousands)					MWh Sales
	2012			2011		2012		2011
Residential	$	43,860		$	43,803		265,964		281,030
Commercial		29,758			28,866		203,430		207,165
Industrial		14,412			10,070		145,664		98,828
Other		545			519		1,599		1,605
Total retail sales		88,575			83,258		616,657		588,628
Resale sales		5,743			7,695		144,822		189,895
Provision for rate refund		(1,047	)		3,391		0		0
Other operating revenues		2,971			2,741		0		0
Total operating revenues	$	96,242		$	97,085		761,479		778,523

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2012 vs. 2011

Operating revenues decreased by $0.9 million for the three months ended March 31, 2012 compared to the same period in 2011 due to the following factors:

Retail sales increased $5.3 million resulting primarily from a 4.78 percent base rate increase, effective January 1, 2012, the acquisition of the Vermont Marble service territory on September 1, 2011, partially offset by weaker customer demand in 2012, due to warmer weather.

Resale sales decreased $1.9 million due to lower volume available for resale due to higher retail load, and lower market rates.

The provision for rate refund decreased $4.4 million primarily due to over- or under-collections of power, production and transmission costs as defined by the power cost adjustment clause of our alternative regulation plan. This decrease included the unfavorable impact of $1 million of net deferrals and refunds in 2012 vs. the favorable impact of $3.4 million of net deferrals and refunds in 2011. In 2011, $4.1 million of revenues were offset by higher regulatory amortizations, included in Other operation as described below.

Other operating revenues increased $0.2 million primarily due to higher sales of renewable energy credits in 2012.

Operating Expenses Operating expenses decreased $1.7 million in the first quarter of 2012 as compared to 2011. 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 for the three months ended March 31 are summarized below:

	Three months ended March 31
	Purchases (in thousands)						MWh purchases
	2012			2011			2012		2011
VYNPC	$	15,221		$	17,056			330,938		390,805
Hydro-Quebec		16,812			16,526			264,824		265,007
Independent Power Producers		6,417			6,279			49,681		48,382
Subtotal long-term contracts		38,450			39,861			645,443		704,194
Other purchases		1,914			1,122			31,381		1,444
Reserve for loss on power contract		(299	)		(299	)		0		0
Nuclear decommissioning		344			356			0		0
Other		79			312			0		0
Total purchased power	$	40,488		$	41,352			676,824		705,638

2012 vs. 2011

Purchased power expense decreased $0.8 million for the three months ended March 31, 2012 compared to the same period in 2011 due to the following factors:

Purchased power costs under long-term contracts decreased $1.4 million in 2012, due primarily to lower output at the Vermont Yankee plant due to the VY PPA terminating on March 21, 2012, partially offset by higher deliveries from Hydro-Québec.

Other purchases increased $0.8 million due to higher volumes from ISO-NE.

Other costs decreased $0.2 million. 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.

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 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 increase of $1.6 million in 2012 was principally due to higher VTA billings due to lower NOATT reimbursements resulting from lower retail loads, and higher cost of service.

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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 decrease of $3.6 million in 2012 was primarily due to lower net regulatory amortizations, largely due to 2011 exogenous costs of $4.1 million, related to major storms and tax law changes. This amount was offset in Provision for rate refund, included in Operating revenues, as described above.

Income tax (benefit) 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 is 38 percent for 2012 and 2011.

Other Income and Other Deductions These items are related to the non-operating activities of our utility business and the operating and non-operating activities of our non-regulated businesses through CRC. CRC’s earnings were less than $0.1 million three months ended March 31, 2012 and 2011. Significant variances in line items that comprise other income and other deductions on the Consolidated Statements of Income are described below.

Other deductions: The decrease of $0.2 million in 2012 is primarily due to changes in the cash surrender value of variable life insurance policies included in our Rabbi Trust, resulting from higher market gains.

Interest on long-term debt: The increase of $0.4 million in 2012 is principally due to interest on long-term debt from bond issuances in June 2011, partially offset by repayment of long-term debt in June 2011.

POWER SUPPLY MATTERS

Power Supply Management Our power supply portfolio includes a mix of baseload, dispatchable resources and intermittent resources. These resources serve our retail electric load requirements and wholesale obligations. We manage our power supply portfolio by attempting to optimize the economic value of these resources and create a balance between our power supplies and load obligations. Also, see Note 13 – Commitments and Contingencies to the accompanying Notes to Consolidated Financial Statements.

Decommissioned Nuclear Plants We own, through equity investments, 2 percent of Maine Yankee, 2 percent of Connecticut Yankee and 3.5 percent of Yankee Atomic. All three have completed decommissioning activities and their operating licenses have been amended to operation of Independent Spent Fuel Storage Installation. They remain separately responsible for safe storage of each plant’s spent nuclear fuel and waste at the sites until the DOE meets its obligation to remove the material from the site or until some other suitable storage arrangement can be developed. All three collect decommissioning and closure costs through FERC-approved wholesale rates charged under power purchase agreements with several New England utilities, including us. We believe that, based on historical rate recovery, our share of decommissioning and closure costs for each plant will continue to be recovered through the regulatory process. However, if the FERC disallows recovery of any of their costs, there is a risk that the PSB would disallow recovery of our share in retail rates.

Based on estimates from Maine Yankee, Connecticut Yankee and Yankee Atomic as of December 31, 2011, the total remaining approximate cost for decommissioning and other costs of each plant is as follows: $18.8 million for Maine Yankee, $175.2 million for Connecticut Yankee and $39.4 million for Yankee Atomic. Our share of the remaining obligations amounts to $0.4 million for Maine Yankee, $3.5 million for Connecticut Yankee and $1.4 million for Yankee Atomic. These estimates may be revised from time to time based on information available regarding future costs.

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

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Oral arguments before the United States Court of Appeals for the Federal Circuit were held on November 7, 2011. The court has yet to issue a decision. Interest on the judgments does not start to accrue until the appeals have been decided. Our share of the claimed damages of $3.2 million is based on our ownership percentages described above. A decision is expected during the second quarter of 2012.

RECENT ENERGY POLICY INITIATIVES

In 2005, the state of Vermont created a renewable energy mandate under SPEED. The primary SPEED goal is that, by July 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.

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 rate for SPEED resources smaller than 2.2 MW in capacity. Feed-In Tariff rates are available for a maximum of 50 MW of capacity. The incremental cost of electricity from Feed-In Tariff 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 Feed-In Tariff. We supported this action.

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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-Québec, which does operate facilities larger than 80 MW. We anticipate no immediate impact from this change in policy.

The 2011 Legislature expanded the size of allowable “net metering projects” from 250 kilowatts to 500 kilowatts, allowed a utility to have twice as much of that type of power in its portfolio as before, and set a premium price for net-metered solar projects. Net metered customers will be allowed to offset credits against all customer charges, and not simply energy charges.

The 2011 Legislature also instructed the DPS to update the state’s energy plan, and, in doing so, to recommend whether Vermont’s SPEED law should be replaced by a more traditional Renewable Portfolio Standard. In September 2011, the DPS issued a Public Review DRAFT 2011 of the Comprehensive Energy Plan for review and comment, and a final plan was issued in December 2011. The plan addresses Vermont’s energy future for electricity, thermal energy, transportation, and land use.

Under the plan, which was updated based on public input, the state intends to set Vermont on a path to obtain 90 percent of its energy in all energy sectors from renewable sources by mid-century. This goal is based on a state desire to virtually eliminate Vermont’s reliance on oil by mid-century “by moving toward enhanced efficiency measures, greater use of clean, renewable sources for electricity, heating, and transportation, and electric vehicle adoption, while increasing our use of natural gas and biofuel blends where nonrenewable fuels remain necessary.” The plan generated significant public comment.

In a separate process, also as required by the 2011 Legislature, the PSB recently issued its “Study on Renewable Energy Requirements.” In that report, the PSB recommends that, by 2033, 1) 10 percent of Vermont’s overall electric portfolio be met with new small-scale renewable distributed generation; 2) 40 percent of Vermont’s overall electric portfolio be met through existing renewable electricity; and 3) 25 percent of Vermont’s overall load be met through new renewable energy, and that utilities be required to retire renewable energy credits starting in 2014.

The 2011-2012 Legislature adjourned on May 5, 2012. Two bills were approved that will encourage incremental expansion of small renewable energy systems through amendments to Vermont’s existing net metering and standard offer laws.

Separately, there was considerable interest in the GMP/CVPS merger partly due to an extensive media campaign by AARP focused on a prior obligation for CVPS to return of $21 million of value to CVPS customers upon the sale of the company. AARP has sought a return of that value in the form of bill credits, rather than through the investments in weatherization and efficiency, as had been the precedent when GMP was purchased by GazMet several years ago. The legislature adjourned without passing any bills that affect the pending merger, which leaves the resolution of AARP 's proposal with the PSB.

ACCOUNTING MATTERS AND TECHNICAL DEVELOPMENTS

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 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 this Form 10-K for the year ended December 31, 2011. Also, see Note 2 - Summary of Significant Accounting Policies to the accompanying Notes to Consolidated Financial Statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Equity Market Risk As of March 31, 2012, our pension trust held marketable equity securities in the amount of $45 million, our postretirement medical trust funds held marketable equity securities in the amount of $12.5 million, our Millstone Unit #3 decommissioning trust held marketable equity securities of $4.9 million and our Rabbi Trust held variable life insurance policies with underlying marketable equity securities of $3 million. In the first quarter of 2012, these equity investments experienced positive performance. In 2011, these equity investments experienced negative performance, except the Millstone Unit #3 decommissioning trust experienced positive performance. Also see Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources, and Note 12 - Pension and Postretirement Medical Benefits for additional information.

Power-related Derivatives We account for some of our power contracts as derivatives under FASB’s guidance for derivatives and hedging. Additional information regarding derivatives is presented in Note 6, Fair Value and Note 10, Power-Related Derivatives.

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We record gains and losses on power-related derivatives and non-derivative power contracts in purchased power and wholesale sales. The PCAM allows us to recover most of our net power costs from customers. 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 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. As a result of the Accounting Order and the PCAM, changes in market prices would not have a material impact to our future financial results.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Management of the company, under the supervision and with participation of our Principal 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 (the “Exchange Act”)), as of March 31, 2012. Based on this evaluation, our Principal Executive Officer and Principal Financial and Accounting Officer concluded that, as of March 31, 2012, the company’s disclosure controls and procedures are effective.

Disclosure controls and procedures are designed to ensure that information required to be disclosed by us in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed under the Exchange Act is accumulated and communicated to management, including the principal executive and financial officers, as appropriate to allow timely decisions regarding required disclosure. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

Changes in Internal Control over Financial Reporting There were no changes in internal control over financial reporting that occurred during the quarter ended March 31, 2012 that have materially affected, or are reasonably likely to materially affect, our 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, including civil litigation. We are unable to fully determine a range of reasonably possible court-ordered damages, settlement amounts, and related litigation costs or legal liabilities that would be in excess of amounts accrued and amounts covered by insurance. Based on the information currently available, we do not believe that it is probable that any such legal liability will have a material impact on our consolidated financial position. However, it is reasonably possible that additional legal liabilities that may result from changes in estimates could have a material impact on our results of operations, financial condition or cash flows.

Litigation Related to Merger Agreement: Davis: The Davis plaintiff filed a revised request for preliminary approval of the settlement agreement. By order dated April 10, 2012, the court 1) approved, for purposes of settlement only, certification of the Davis lawsuit as a class action under the federal rules; 2) certified plaintiff Howard Davis as the Class representative; 3) scheduled a Fairness Hearing for July 11, 2012, to determine a number of issues including whether the court should approve the Settlement Agreement and a request by Plaintiff's counsel for attorney's fees.

IBEW: On January 12, 2012, the parties to the state court lawsuits filed a stipulation for dismissal without prejudice of those proceedings. On January 24, 2012, the state court entered an order stating that the state court lawsuits would be dismissed without prejudice unless it received a filed objection by January 31, 2012. No such objection was filed.

Item 1A.

Risk Factors.

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part Ι “Item 1A. Risk Factors”, in our Annual Report on Form 10-K for the year ended December 31, 2011, which could materially affect our business, financial condition or future results.

Item 6.

Exhibits.

(a)

List of Exhibits

A 10.21

Separation Agreement between Pamela J. Keefe and Central Vermont Public Service Corporation dated effective April 1, 2012 (incorporated by reference to Exhibit A 10.21 to the Company’s Form 8-K filed with the SEC on April 4, 2012).

A 10.22

General Release between Pamela J. Keefe and Central Vermont Public Service Corporation dated effective April 1, 2012 (incorporated by reference to Exhibit A 10.22 to the Company’s Form 8-K filed with the SEC on April 4, 2012).

A 10.23

Consulting Services Agreement between Pamela J. Keefe and Central Vermont Public Service Corporation dated effective April 1, 2012 (incorporated by reference to Exhibit A 10.23 to the Company’s Form 8-K filed with the SEC on April 4, 2012).

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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101.INS

XBRL Instance Document

101.SCH

XBRL Schema Document

101.CAL

XBRL Calculation Linkbase Document

101.DEF

XBRL Definition Linkbase Document

101.LAB

XBRL Label Linkbase Document

101.PRE

XBRL Presentation Linkbase Document

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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/ Edmund F. Ryan
		Edmund F. Ryan
		Acting Chief Financial Officer, and Treasurer

Dated May 9, 2012

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CENTRAL VERMONT PUBLIC SERVICE CORP 10-Q