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    September 30, 2011    

or

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

For the transition period from  to 

Commission file number 1-8222

Central Vermont Public Service Corporation

(Exact name of registrant as specified in its charter)

Vermont (State or other jurisdiction of incorporation or organization)	03-0111290 (IRS Employer Identification No.)
77 Grove Street, Rutland, Vermont (Address of principal executive offices)	05701 (Zip Code)

Registrant's telephone number, including area code (800) 649-2877

N/A

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

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

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 o

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 o	Accelerated filer  x
Non-accelerated filer o(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 o 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 October 31, 2011 there were outstanding 13,431,449 shares of Common Stock, $6 Par Value.

CENTRAL VERMONT PUBLIC SERVICE CORPORATION

Form 10-Q for Period Ended September 30, 2011

Table of Contents

PART I.   Financial Information:

		Page
Item 1.	Financial Statements
	Unaudited Condensed Consolidated Statements of Operations	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	39
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	56
Item 4.	Controls and Procedures	57
PART II.   Other Information:
Item 1.	Legal Proceedings	58
Item 1A.	Risk Factors	59
Item 6.	Exhibits	60
SIGNATURES		61

Page 1 of 61

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.

Page 2 of 61

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

Page 3 of 61

PART I. FINANCIAL INFORMATION

Item 1.  Financial Statements

CENTRAL VERMONT PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(dollars in thousands, except per share data)

(unaudited)

	Three months ended						Nine months ended
	September 30						September 30
	2011			2010			2011			2010
Operating Revenues	$	88,051		$	85,392		$	269,404		$	256,336
Operating Expenses
Purchased Power – affiliates		16,347			16,817			51,215			43,889
Purchased Power		21,516			24,292			67,778			76,149
Production		2,931			3,169			8,342			8,785
Transmission – affiliates		1,047			(5,055	)		6,585			(2,001	)
Transmission – other		7,030			7,027			20,431			20,272
Other operation		5,893			10,597			39,865			42,279
Maintenance		17,375			6,637			30,589			21,755
Depreciation		4,849			4,399			13,929			13,081
Taxes other than income		4,876			4,473			13,952			13,686
Income tax expense		1,762			4,407			4,138			5,454
Total Operating Expenses		83,626			76,763			256,824			243,349
Utility Operating Income		4,425			8,629			12,580			12,987
Other(Loss) Income
Equity in earnings of affiliates		6,821			5,347			20,749			15,857
Allowance for equity funds during construction		(19	)		42			65			52
Other income		698			706			2,100			2,139
Other deductions		(24,163	)		(257	)		(28,463	)		(1,857	)
Income tax benefit (expense)		7,140			(1,631	)		3,616			(4,934	)
Total Other (Loss) Income		(9,523	)		4,207			(1,933	)		11,257
Interest Expense
Interest on long-term debt		3,478			2,750			9,813			8,292
Other interest		150			117			437			343
Allowance for borrowed funds during construction		(80	)		(21	)		(118	)		(28	)
Total Interest Expense		3,548			2,846			10,132			8,607
Net (Loss) Income		(8,646	)		9,990			515			15,637
Dividends declared on preferred stock		92			92			276			276
(Loss) Earnings available for common stock	$	(8,738	)	$	9,898		$	239		$	15,361
Per Common Share Data:
Basic (loss) earnings per share	$	(0.65	)	$	0.79		$	0.02		$	1.27
Diluted (loss) earnings per share	$	(0.65	)	$	0.79		$	0.02		$	1.27
Average shares of common stock outstanding - basic		13,425,986			12,516,488			13,393,293			12,109,796
Average shares of common stock outstanding - diluted		13,425,986			12,545,987			13,482,376			12,140,191
Dividends declared per share of common stock	$	0.23		$	0.23		$	0.92		$	0.92

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

Page 4 of 61

CENTRAL VERMONT PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(dollars in thousands)

(unaudited)

	Three months ended					Nine months ended
	September 30					September 30
	2011			2010		2011		2010
Net (Loss) Income	$	(8,646	)	$	9,990	$	515	$	15,637
Other comprehensive (loss) income, net of tax:
Defined benefit pension and postretirement medical plans:
Portion reclassified through amortizations, included in benefit costs and recognized in net (loss) income:
Actuarial losses, net of income taxes of $0, $0, $64 and $0		0			0		95		0
Change in funded status of pension, postretirement medical and other benefit plans, net of income taxes of $0, $0, $26 and $0		0			0		38		0
									0
Comprehensive income adjustments		0			0		133		0
Total comprehensive (loss) income	$	(8,646	)	$	9,990	$	648	$	15,637

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

Page 5 of 61

CENTRAL VERMONT PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)

(unaudited)

	Nine months ended September 30
Cash flows provided by:	2011			2010
OPERATING ACTIVITIES
Net Income	$	515		$	15,637
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of affiliates		(20,749	)		(15,857	)
Distributions received from affiliates		14,031			10,788
Depreciation		13,929			13,081
Deferred income taxes and investment tax credits		3,722			15,641
Regulatory and other deferrals and amortization		(4,551	)		(2,446	)
Non-cash employee benefit plan costs		4,733			4,884
Other non-cash expense and (income), net		(2,098	)		(573	)
Changes in assets and liabilities:
Fortis termination fee reimbursement from Gaz Métro		19,500			0
Decrease in accounts receivable and unbilled revenues		4,046			188
Decrease in accounts payable		(141	)		(2,346	)
Change in prepaid and accrued income taxes		6,028			(884	)
Increase in other current assets		(1,071	)		(1,726	)
(Increase) decrease in special deposits and restricted cash		(1,179	)		5,370
Employee benefit plan funding		(7,583	)		(6,351	)
Increase in other current liabilities		13,973			1,330
(Increase) decrease in other long-term assets and liabilities and other		(1,384	)		1,306
Net cash provided by operating activities		41,721			38,042
INVESTING ACTIVITIES
Construction and plant expenditures		(27,415	)		(21,012	)
Acquisition of utility property (Vermont Marble and Readsboro)		(29,732	)		0
Reimbursements of restricted cash - bond proceeds		12,973			0
Project reimbursement from DOE		851			0
Investments in available-for-sale securities		(1,241	)		(1,146	)
Proceeds from sale of available-for-sale securities		1,074			937
Other investing activities		(248	)		(402	)
Net cash used for investing activities		(43,738	)		(21,623	)
FINANCING ACTIVITIES
Net proceeds from the issuance of common stock		1,393			18,489
Decrease in special deposits for preferred stock mandatory redemption		0			1,000
Retirement of preferred stock subject to mandatory redemption		0			(1,000	)
Common and preferred dividends paid		(9,514	)		(8,605	)
Proceeds from revolving credit facility and other short-term borrowings		53,801			114,043
Repayments under revolving credit facility and other short-term borrowings		(63,515	)		(137,354	)
Proceeds from long-term debt		40,000			0
Repayment of long-term debt		(20,000	)		0
Common stock offering and debt issue costs		(214	)		(322	)
Reduction in capital lease and other financing activities		(900	)		(794	)
Net cash provided by (used for) financing activities		1,051			(14,543	)
Net change in cash and cash equivalents		(966	)		1,876
Cash and cash equivalents at beginning of the period		2,676			2,069
Cash and cash equivalents at end of the period	$	1,710		$	3,945

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

Page 6 of 61

CENTRAL VERMONT PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(dollars in thousands, except share data)

(unaudited)

	September 30, 2011		December 31, 2010
ASSETS
Utility plant
Utility plant, at original cost	$	664,174	$	611,746
Less accumulated depreciation		277,009		266,649
Utility plant, at original cost, net of accumulated depreciation		387,165		345,097
Property under capital leases, net		3,713		4,425
Construction work-in-progress		17,639		20,234
Nuclear fuel, net		2,877		1,737
Total utility plant, net		411,394		371,493
Investments and other assets
Investments in affiliates		178,343		171,514
Non-utility property, less accumulated depreciation ($3,198 in 2011 and $3,164 in 2010)		2,244		2,196
Millstone decommissioning trust fund		5,739		5,742
Restricted cash		8,208		17,581
Other		6,916		7,013
Total investments and other assets		201,450		204,046
Current assets
Cash and cash equivalents		1,710		2,676
Restricted cash		3,520		5,903
Special deposits		6		6
Accounts receivable, less allowance for uncollectible accounts ($2,728 in 2011 and $2,649 in 2010)		26,204		28,552
Accounts receivable - affiliates, less allowance for uncollectible accounts		1,473		314
Unbilled revenues		16,828		21,003
Materials and supplies, at average cost		7,123		7,159
Prepayments		13,961		15,862
Deferred income taxes		11,218		4,501
Power-related derivatives		37		28
Regulatory assets		1,935		1,924
Other deferred charges - regulatory		4,106		2,078
Other deferred charges and other assets		1,133		0
Other current assets		1,988		1,114
Total current assets		91,242		91,120
Deferred charges and other assets
Regulatory assets		36,118		38,552
Other deferred charges - regulatory		7,021		2,260
Other deferred charges and other assets		4,325		3,275
Power-related derivatives		236		0
Total deferred charges and other assets		47,700		44,087
TOTAL ASSETS	$	751,786	$	710,746

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

Page 7 of 61

CENTRAL VERMONT PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(dollars in thousands, except share data)

(unaudited)

	September 30, 2011			December 31, 2010
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock, $6 par value, 19,000,000 shares authorized, 15,558,869 issued and 13,429,796 outstanding at September 30, 2011 and 15,470,217 issued and 13,341,144 outstanding at December 31, 2010	$	93,353		$	92,821
Other paid-in capital		95,565			94,462
Accumulated other comprehensive loss		(99	)		(232	)
Treasury stock, at cost, 2,129,073 shares at September 30, 2011 and December 31, 2010		(48,436	)		(48,436	)
Retained earnings		122,026			134,113
Total common stock equity		262,409			272,728
Preferred and preference stock not subject to mandatory redemption		8,054			8,054
Long-term debt		232,281			188,300
Capital lease obligations		2,768			3,471
Total capitalization		505,512			472,553
Current liabilities
Current portion of long-term debt		0			20,000
Accounts payable		7,556			8,137
Accounts payable - affiliates		11,065			11,835
Notes payable		0			13,695
Nuclear decommissioning costs		1,533			1,438
Power-related derivatives		1,963			0
Other deferred credits - regulatory		933			1,108
Other current liabilities		60,343			30,763
Total current liabilities		83,393			86,976
Deferred credits and other liabilities
Deferred income taxes		93,308			82,406
Deferred investment tax credits		2,195			2,387
Nuclear decommissioning costs		4,227			5,383
Asset retirement obligations		3,845			3,609
Accrued pension and benefit obligations		28,219			32,441
Power-related derivatives		89			0
Other deferred credits - regulatory		3,422			3,886
Other deferred credits and other liabilities		27,576			21,105
Total deferred credits and other liabilities		162,881			151,217
Commitments and contingencies (Note 13)
TOTAL CAPITALIZATION AND LIABILITIES	$	751,786		$	710,746

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

Page 8 of 61

CENTRAL VERMONT PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN COMMON STOCK EQUITY

(in thousands, except share data)

(unaudited)

	Common Stock				Treasury Stock
														Accumulated
											Other			Other
	Shares										Paid-in			Comprehensive			Retained
	Issued		Amount		Shares			Amount			Capital			Loss			Earnings			Total
Balance, December 31, 2009		13,835,968	$	83,016		(2,129,073	)	$	(48,436	)	$	72,179		$	(209	)	$	124,873		$	231,423
Net income																		15,637			15,637
Other comprehensive income
Common Stock Issuance, net of issuance costs		848,057		5,088								11,657									16,745
Dividend reinvestment plan		52,314		314								728									1,042
Stock options exercised		35,100		210								301									511
Share-based compensation:
Common & nonvested shares		2,484		15								40									55
Performance share plans		15,121		91								(59	)								32
Dividends declared:
Common - $0.92 per share																		(11,215	)		(11,215	)
Cumulative non-redeemable preferred stock																		(276	)		(276	)
Amortization of preferred stock issuance expense												12									12
Gain (Loss) on capital stock												2						(2	)		0
Balance, September 30, 2010		14,789,044	$	88,734		(2,129,073	)	$	(48,436	)	$	84,860		$	(209	)	$	129,017		$	253,966

	Common Stock				Treasury Stock
														Accumulated
											Other			Other
	Shares										Paid-in			Comprehensive			Retained
	Issued		Amount		Shares			Amount			Capital			Loss			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																		515			515
Other comprehensive income															133						133
Dividend reinvestment plan		37,977		228								743									971
Stock options exercised		26,200		157								265									422
Share-based compensation:
Common & nonvested shares		7,075		43								107									150
Performance share plans		17,400		104								(24	)								80
Dividends declared:
Common - $0.92 per share																		(12,326	)		(12,326	)
Cumulative non-redeemable preferred stock																		(276	)		(276	)
Amortization of preferred stock issuance expense												12									12
Balance, September 30, 2011		15,558,869	$	93,353		(2,129,073	)	$	(48,436	)	$	95,565		$	(99	)	$	122,026		$	262,409

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

Page 9 of 61

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, FERC and the PSB; and the absence of any governmental action challenging or seeking to prohibit 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 pay Gaz Métro a termination fee of $17.5 million and reimburse Gaz Métro for up to $2 million of its reasonable out-of-pocket transaction expenses.

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.

In addition, we made other regulatory filings seeking approval of the proposed merger, including with the Nuclear Regulatory Commission, the Federal Energy Regulatory Commission, the Federal Trade Commission, Federal Communications Commission, 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 proposed merger.

Shareholder Approval:  On September 29, 2011, CVPS held a Special Meeting of Shareholders (“Special Meeting”), in Rutland, Vermont.  The shareholders approved the Agreement and Plan of Merger, effective as of July 11, 2011, in a non-binding advisory vote and approved the change-in-control payments related to the merger.  Over 75 percent of the outstanding shares of the company were represented at the meeting, and of those, more than 97 percent voted in support of the sale. 

Page 10 of 61

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 (“Merger Sub”) 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”), including the termination fee of $17.5 million and expenses of FortisUS Inc. of $2 million. These amounts have been recorded to Other deductions on the Condensed Consolidated Statements of Operations in the three-month period ended September 30, 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 reimburse Gaz Métro for the full amount of the Fortis Termination Payment 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.

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.

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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 Gaz Métro merger were misleading and/or incomplete, and that the CVPS Board had violated its fiduciary duties.  The proposed consolidated amended complaint also contains claims for aiding and abetting fiduciary breaches against CVPS and Gaz Métro.  The proposed consolidated amended complaint seeks, 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.

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 proposed Gaz Métro 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 proposed 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. The parties to the Davis action have informed the court of the memorandum of understanding and will be seeking court approval of the proposed settlement. The parties to the MOU reserved their rights with respect to the determination of plaintiffs’ attorneys fees, if any, when our settlement agreement is reviewed by the court.

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, contains 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.

On October 14, 2011, CVPS and the other defendants filed motions to dismiss the federal IBEW 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 interim financial statements contain all normal, recurring adjustments considered necessary to present fairly the financial position as of September 30, 2011, and the results of operations and cash flows for the three and nine months ended September 30, 2011 and 2010. 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 financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our annual report on Form 10K for the year ended December 31, 2010.

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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 Operations 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: 1) increasing competition that restricts a company’s ability to establish prices to recover specific costs, and 2) a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation.  See Note 9 - Retail Rates and Regulatory Accounting for additional information.

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

Based on a PSB-approved accounting order, we record the changes in fair value of all power-related derivative financial instruments as deferred charges or deferred credits on the balance sheet, depending on whether the change in fair value is an unrealized loss or gain.  Realized gains and losses on sales are recorded as increases to or reductions of operating revenues, respectively. For purchase contracts, realized gains and losses are recorded as reductions of or additions to purchased power expense, respectively.  For additional information about power-related derivatives, see Note 6 - Fair Value and Note 10 - Power-Related Derivatives.

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

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We record government grants receivable in the Condensed Consolidated Balance Sheets in Accounts Receivable. For additional information see Note 9 – Retail Rates and Regulatory Accounting – CVPS SmartPower®.

Our current rates include the recovery of costs that are eligible for government grant reimbursement by the DOE under the ARRA; however, prior to January 1, 2011, the grant reimbursements were not reflected in our current rates.  The grant reimbursements were recorded to a regulatory liability. Effective January 1, 2011 grant reimbursements are reflected in our rates.

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

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

	September 30, 2011		December 31, 2010
Taxes	$	12,242	$	14,662
Insurance		679		412
Miscellaneous		1,040		788
Total	$	13,961	$	15,862

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

	September 30, 2011		December 31, 2010
Deferred compensation plans and other	$	822	$	2,596
Accrued employee-related costs		4,137		4,660
Other taxes and Energy Efficiency Utility		5,965		4,105
Cash concentration account - outstanding checks		1,046		2,358
Obligation under capital leases		937		942
Provision for rate refund		612		5,137
Accrued Interest		4,349		938
Common dividends declared		3,089		0
Fortis Termination Reimbursement		19,500		0
Tropical Storm Irene expense accrual		4,502		0
Miscellaneous accruals		15,384		10,027
Total	$	60,343	$	30,763

Other Deductions:  The components of Other deductions on the Condensed Consolidated Statement of Operations follow (dollars in thousands):

	Three months end				Nine months ended
	September 30				September 30
	2011		2010		2011		2010
Fortis termination fee	$	19,500		0	$	19,500		0
Other merger-related fees		3,356		0		6,565		0
Other		1,307	$	257		2,398	$	1,857
Total	$	24,163	$	257	$	28,463	$	1,857

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NOTE 3 - EARNINGS PER SHARE

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

	Three months ended						Nine months ended
	September 30						September 30
	2011			2010			2011			2010
Numerator for basic and diluted EPS:
Net (loss) income	$	(8,646	)	$	9,990		$	515		$	15,637
Dividends declared on preferred stock		(92	)		(92	)		(276	)		(276	)
Net (loss) income available for common stock	$	(8,738	)	$	9,898		$	239		$	15,361
Denominators for basic and diluted EPS:
Weighted-average basic shares of common stock outstanding		13,425,986			12,516,488			13,393,293			12,109,796
Dilutive effect of stock options		-			11,232			52,798			14,343
Dilutive effect of performance shares		-			18,267			36,285			16,052
Weighted-average diluted shares of common stock outstanding		13,425,986			12,545,987			13,482,376			12,140,191

Stock Options:  The outstanding stock options were excluded from the computation of diluted shares for the third quarter due to the antidilutive impact; however, there were no shares excluded for the first nine months of 2011 because the prices were above the current average market price and there was no antidilutive impact.  Outstanding stock options totaling 42,577 for the third quarter and 44,799 for the first nine months of 2010 were excluded from the computation of diluted shares because the prices were above the current average market price.

Performance Shares:  The outstanding performance shares were excluded from the computation of diluted shares for the third quarter due to the antidilutive impact.  In the first nine months of 2011, there were 2,507 shares excluded because the performance share measures were not met; however, there was no antidilutive impact. Outstanding performance shares totaling 60,723 for the third quarter and first nine months of 2010 were excluded from the computation of diluted shares as either the performance share measures were not met or there was an antidilutive impact.

NOTE 4 - INVESTMENTS IN AFFILIATES

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

	Three months ended						Nine months ended
	September 30						September 30
	2011			2010			2011			2010
Operating revenues	$	33,172		$	25,408		$	101,311		$	76,610
Operating income	$	19,217		$	13,231		$	58,484		$	42,218
Income before non-controlling interest and income tax	$	15,563		$	12,622		$	47,163		$	37,592
Less members' non-controlling interest in income		14,532			11,495			43,606			34,400
Less income tax		508			130			1,441			656
Net income	$	523		$	997		$	2,116		$	2,536
Company's common stock ownership interest		47.10	%		47.05	%		47.10	%		47.05	%
Company's equity in net income	$	245		$	468		$	997		$	1,142

Accounts payable to VELCO were $5.8 million at September 30, 2011 and December 31, 2010.

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

	Three months ended						Nine months ended
	September 30						September 30
	2011			2010			2011			2010
Operating revenues	$	33,288		$	25,601		$	101,729		$	77,618
Operating income	$	19,957		$	13,946		$	60,742		$	44,225
Net income	$	15,965		$	13,098		$	48,239		$	39,258
Company's ownership interest		36.71	%		33.33	%		36.71	%		33.33	%
Company's equity in net income	$	6,522		$	4,861		$	19,572		$	14,559

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 ISO-NE Open Access Transmission Tariff 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 $1 million in the third quarter and $6.6 million in the first nine months of 2011 and net credits of $5.1 million in the third quarter and $2 million in the first nine months of 2010. These amounts are included in Transmission - affiliates on our Condensed Consolidated Statements of Operations.  Accounts payable to Transco were $0.3 million at September 30, 2011 and there were no accounts payable due at December 31, 2010.   Accounts receivable from Transco was $0.2 million at December 31, 2010.

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

	Three months ended						Nine months ended
	September 30						September 30
	2011			2010			2011			2010
Operating revenues	$	45,922		$	47,289		$	144,015		$	123,061
Operating (loss) income	$	(350	)	$	(177	)	$	(1,167	)	$	(1,616	)
Net income	$	92		$	27		$	302		$	253
Company's common stock ownership interest		58.85	%		58.85	%		58.85	%		58.85	%
Company's equity in net income	$	54		$	16		$	178		$	149

VYNPC’s revenues shown in the table above include sales to us of $16 million in the third quarter and $50.2 million in the first nine months of 2011 and $16.5 million in the third quarter and $42.9 million in the first nine months of 2010. These amounts are included in Purchased power - affiliates on our Condensed Consolidated Statements of Operations.  Accounts payable to VYNPC were $4.9 million at September 30, 2011 and $5.9 million at December 31, 2010.

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 2010, VYNPC has accumulated $142 million in an irrevocable trust to be used exclusively for meeting this obligation ($144.6 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.

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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, which 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 September 30, 2011, we had regulatory assets of $0.5 million for Maine Yankee, $3.7 million for Connecticut Yankee and $1.5 million for Yankee Atomic.  These estimated costs are being collected from customers through existing retail rate tariffs.  Total billings from the three companies amounted to $0.4 million in the third quarter and $1.1 million in the first nine months of 2011 and $0.3 million in the third quarter and $1 million in the first nine months of 2010. These amounts are included in Purchased power - affiliates on our Condensed Consolidated Statements of Operations.

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

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.

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On July 1, 2009, Maine Yankee, Connecticut Yankee and Yankee Atomic filed 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.  The trial began October 11, 2011.

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.

NOTE 5 - FINANCIAL INSTRUMENTS

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

	September 30, 2011				December 31, 2010
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
Power contract derivative assets (includes current portion)	$	273	$	273	$	28	$	28
Power contract derivative liabilities (includes current portion)	$	2,052	$	2,052	$	0	$	0
Long-term debt:
First mortgage bonds (includes current portion)	$	187,500	$	234,937	$	167,500	$	188,467
Industrial/Economic Development bonds	$	40,800	$	41,919	$	40,800	$	40,521
Credit facility borrowings	$	3,981	$	3,981	$	13,695	$	13,695

At September 30, 2011, our power-related derivatives consisted of FTRs and forward energy contracts.  There were no related unrealized gains or losses in the first nine months of 2011 or 2010.  For a discussion of the valuation techniques used for power contract derivatives see Note 6 - Fair Value - Power-related Derivatives below.

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

Effective January 1, 2008, we adopted 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.

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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.

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 sales, financial transmission rights and a power-related option contract.  There were no changes to our Level 3 fair value measurement methodologies during 2011 and 2010.

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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 September 30, 2011
	Level 1		Level 2		Level 3		Total
Assets:
Millstone decommissioning trust fund
Investments in securities:
Marketable equity securities	$	1,554	$	2,738			$	4,292
Marketable debt securities
Corporate bonds				335				335
U.S. Government issued debt securities (Agency and Treasury)				998				998
State and municipal				28				28
Other				29				29
Total marketable debt securities				1,390				1,390
Cash equivalents and other				57				57
Total investments in securities		1,554		4,185				5,739
Restricted cash - long-term				8,208				8,208
Cash equivalents				981				981
Restricted cash				3,520				3,520
Power-related derivatives - current					$	37		37
Power-related derivatives - long term						236		236
Total assets	$	1,554	$	16,894	$	273	$	18,721
Liabilities:
Power-related derivatives - current					$	1,963	$	1,963
Power-related derivatives - long term						89	$	89
Total liabilities	$	0	$	0	$	2,052	$	2,052

	Fair Value as of December 31, 2010
	Level 1		Level 2		Level 3		Total
Assets:
Millstone decommissioning trust fund
Investments in securities:
Marketable equity securities	$	1,587	$	2,776			$	4,363
Marketable debt securities
Corporate bonds				350				350
U.S. Government issued debt securities (Agency and Treasury)				911				911
State and municipal				38				38
Other				36				36
Total marketable debt securities				1,335				1,335
Cash equivalents and other				44				44
Total investments in securities		1,587		4,155				5,742
Restricted cash - long-term				17,581				17,581
Cash equivalents		1,653						1,653
Restricted cash				5,903				5,903
Power-related derivatives - current						28		28
Total assets	$	3,240	$	27,639	$	28	$	30,907

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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 periods ended September 30, 2011 and 2010.

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 90-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 September 30, 2011, our derivatives consisted of forward energy contracts and FTRs.  At December 31, 2010, 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.  Since many of the valuation inputs are not observable in the market, we have classified our derivative assets and liabilities as Level 3.

To calculate the fair value of 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.

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.

To calculate the fair value of our power-related option contract, which expired at December 31, 2010, we used a binomial tree model that included the following inputs: forward energy prices, expected volatility, contract volume, prices and duration, and LIBOR swap rates.

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 (dollars in thousands):

	Three months ended September 30						Nine months ended September 30
	2011			2010			2011			2010
Balance as of beginning of period	$	92		$	2,829		$	28		$	254
Gains and losses (realized and unrealized)
Included in earnings		(117	)		289			(127	)		2,408
Included in Regulatory and other assets/liabilities		(1,844	)		(106	)		(1,785	)		2,536
Purchases		0			0			20			0
Net settlements		90			(323	)		85			(2,509	)
Balance at September 30	$	(1,779	)	$	2,689		$	(1,779	)	$	2,689

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At September 30, 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.

In the third quarter of 2011, we had $0.1 million of realized gains and $0.1 million of realized losses.  The realized losses include small 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 third quarter of 2011.

In the first nine months of 2011, we had $0.2 million of realized gains and $0.2 million of realized losses.  The realized losses include small 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 nine months of 2011.

For the third quarter of 2010, we had nominal realized gains and losses. The realized losses include minimal impairments associated with our equity securities.

For the first nine months of 2010, we had less than $0.1 million of realized gains and less than $0.1 million of realized losses. The realized losses include $0.1 million of impairments associated with our equity securities.  There were no non-credit loss impairments of our debt securities. In 2010, there were also no permanent impairments or ‘credit losses’ associated with our debt securities.

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

	As of September 30, 2011
	Amortized		Unrealized		Unrealized			Estimated
Security Types	Cost		Gains		Losses			Fair Value
Marketable equity securities	$	3,099	$	1,193	$	0		$	4,292
Marketable debt securities
Corporate bonds		310		25	$	0			335
U.S. Government issued debt securities (Agency and Treasury)		919		79		0			998
State and municipal		28		1		(1	)		28
Other		28		1		0			29
Total marketable debt securities		1,285		106		(1	)		1,390
Cash equivalents and other		57		0		0			57
Total	$	4,441	$	1,299	$	(1	)	$	5,739

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	As of December 31, 2010
	Amortized		Unrealized		Unrealized			Estimated
Security Types	Cost		Gains		Losses			Fair Value
Marketable equity securities	$	3,075	$	1,288				$	4,363
Marketable debt securities
Corporate bonds		333		19	$	(2	)		350
U.S. Government issued debt securities (Agency and Treasury)		861		53		(3	)		911
State and municipal		37		1					38
Other		35		1					36
Total marketable debt securities		1,266		74		(5	)		1,335
Cash equivalents and other		44							44
Total	$	4,385	$	1,362	$	(5	)	$	5,742

Information related to the fair value of debt securities at September 30, 2011 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	$	74	$	265	$	284	$	767	$	1,390

At September 30, 2011, the fair value of debt securities in an unrealized loss position was less than $0.1 million.  At December 31, 2010, the fair value of debt securities in an unrealized loss position was $0.2 million.

NOTE 8 – RESTRICTED CASH

At September 30, 2011, we had $10.5 million invested in a restricted cash account related to unreimbursed VEDA bond financing proceeds. 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.

As of September 30, 2011, we recorded $2.3 million of the restricted cash as a current asset on the Condensed Consolidated Balance Sheet, which represents expenses paid that are expected to be reimbursed at the next requisition date.  To date we have received reimbursements of $19.5 million.  We expect to receive reimbursements of the remaining proceeds held in trust by early 2012.

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 September 30, 2011, the $1.1 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 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 shortfall 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.

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The ESAM also provides for an exogenous effects provision.  Under this provision, we are allowed to defer 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 the third quarter of 2011, we deferred $8.6 million of costs related to Tropical Storm Irene and legislative and tax law changes.  We plan to file with the PSB by 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 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 2010 return on equity from the regulated portion of our business was 8.95 percent. We filed this calculation with the PSB in April 2011. No ESAM adjustment was required since this return was within 75 basis points of our 2010 allowed return on equity of 9.59 percent.  On May 20, 2011 the DPS notified the PSB that they agreed with our conclusion that an adjustment for the 2010 ESAM was not required.  On May 26, 2011 the PSB accepted our 2010 ESAM calculation.

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 will be collected from customers over the three months ending March 31, 2012. We filed a PCAM report with the PSB identifying this under-collection.  The PSB has not yet acted on this filing.

The PCAM adjustment for the second quarter of 2011 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 December 31, 2011. We filed a PCAM report with the PSB identifying this over-collection.  The DPS recommended the PCAM report be approved as filed and the PSB accepted the DPS recommendation and approved the filing.

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 proposes 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.  The base rate filing will become effective January 1, 2012 unless suspended by the PSB.  We cannot predict the outcome of this matter at this time.

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.  As a participant on Vermont’s smart grid stimulus application, we expect to receive a grant of over $31 million.

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 eligible to receive reimbursement of 50 percent of our total project costs incurred since August 6, 2009, up to $31 million.  From the inception of the project through September 30, 2011, we have incurred $10.7 million of costs, of which $6.6 million were operating expenses and $4.1 million were capital expenditures.  In the third quarter of 2011, we recorded $3.1 million to various operating expenses and $4.2 million was recorded in the first nine months.

We have submitted requests for reimbursement of $5 million and have received $3.4 million to date, of which $1.1 million was received in 2011.

On July 19, 2011, we entered into a contract for the communications infrastructure in support of our advanced metering project.  The overall contract is approximately $6.2 million for which we are jointly and severally liable with another party.  Our share of the contract cost is approximately $3.9 million.  The contract calls for a $1.9 million initial payment with remaining payments for certain milestones to be made over a two-year period.  In August 2011, we made the initial payment of $1.9 million and submitted this payment to the DOE for 50 percent reimbursement.

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

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 $11.4 million of regulatory assets (total regulatory assets of $38.1 million less pension and postretirement medical costs of $26.7 million), $11.1 million of other deferred charges - regulatory and $4.4 million of other deferred credits - regulatory.  This would result in a total charge to operations of $18.1 million on a pre-tax basis as of September 30, 2011.  We would be required to record pre-tax pension and postretirement costs of $26.4 million to Accumulated Other Comprehensive Loss and $0.3 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.

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Regulatory assets, certain other deferred charges and other deferred credits are shown in the table below (dollars in thousands).

	September 30, 2011		December 31, 2010
Regulatory Assets - Long-term Portion:
Pension and postretirement medical costs	$	26,504	$	27,959
Nuclear plant dismantling costs		4,227		5,383
Income taxes		4,662		4,480
Asset retirement obligations and other		725		730
Total Regulatory Assets -Long-term Portion		36,118		38,552
Regulatory Assets - Current Portion:
Pension and postretirement medical costs		235		0
Nuclear refueling outage costs - Millstone Unit #3		0		486
Nuclear plant dismantling costs		1,533		1,438
Asset retirement obligations and other		167		0
Total Regulatory Assets - Current Portion		1,935		1,924
Total Regulatory Assets		38,053	$	40,476
Other Deferred Charges - Regulatory - Long-term Portion:
Unrealized loss on power-related derivatives		89		0
ESAM deferred costs		6,429		2,079
Environmental		497		0
Other		6		181
Total Other Deferred Charges - Regulatory - Long-term Portion		7,021		2,260
Other Deferred Charges - Regulatory - Current Portion:
Unrealized loss on power-related derivatives		1,963		0
ESAM deferred costs		2,143		2,078
Total Other Deferred Charges - Regulatory - Current Portion		4,106		2,078
Total Other Deferred Charges - Regulatory	$	11,127	$	4,338
Other Deferred Credits - Regulatory - Long-term Portion:
Asset retirement obligation - Millstone Unit #3		2,888	$	3,009
Unrealized gains on power-related derivatives		0		0
CVPS SmartPower® grant reimbursements		222		222
Other		312		655
Total Other Deferred Credits - Regulatory - Long-term Portion:		3,422		3,886
Other Deferred Credits - Regulatory - Current Portion:
Unrealized gains on power-related derivatives		267		0
CVPS SmartPower® grant reimbursements		239		958
Other		427		150
Total Other Deferred Credits - Regulatory - Current Portion		933		1,108
Total Other Deferred Credits - Regulatory	$	4,355	$	4,994

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

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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.  Currently, our power supply forecast shows energy purchase and production amounts in excess of our load requirements through early 2012.  Because of this projected power surplus, we entered into one forward power sale contract for 2011.  The 2011 forward sale was initially structured as a physical sale of excess power.  In January 2011 the sale contract was renegotiated as a rate swap that settles financially.  We recently entered into a similar rate swap for the sale of excess power in January and February 2012.  We have concluded that neither the 2011 or 2012 rate swaps are derivatives, since a notional amount does not exist under the terms of either contract.

On occasion, we will forecast a temporary power supply shortage such as when Vermont Yankee becomes unavailable.  We typically enter into short-term forward power purchase contracts to cover a portion of these expected power supply shortages, which helps to reduce price volatility in our net power costs.  We recently entered into a 26-day purchase contract to cover the expected power supply shortage during the 2011 Vermont Yankee refueling outage, which ended November 3, 2011.  Our power supply forecast shows that in early 2012, when our long-term contract with Vermont Yankee expires, our load requirements will begin to exceed the level of energy we currently purchase and produce.  In July 2011, we also entered into two contracts to fill what would have been power supply shortages expected between April and December 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 did not elect the “normal purchase, normal sale” exception for any of the 2011 and 2012 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 - New Hydro-Québec Agreement.

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 - Derivative Financial Instruments.

Outstanding power-related derivative contracts at are as follows:

	MWh (000s)
	September 30, 2011		December 31, 2010
Commodity
Forward Energy Purchase Contracts		593.7		0
Financial Transmission Rights		491.6		1958.3

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

	Three months ended					Nine months ended
	September 30					September 30
	2011			2010		2011			2010
Net realized gains (losses) reported in operating revenues	$	0		$	284	$	0		$	2,984
Net realized gains (losses) reported in purchased power		(117	)		5		(127	)		(576	)
Net realized gains (losses) reported in earnings	$	(117	)	$	289	$	(127	)	$	2,408

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 Condensed Consolidated Statements of Cash Flows.  For information on the location and amounts of derivative fair values on the Condensed Consolidated Balance Sheets see Note 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 September 30, 2011 was $1.6 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 $1 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 $0.6 million of collateral.   We had no derivative instruments with credit-risk-related contingent features that were in a liability position on December 31, 2010.  For information concerning performance assurance, see Note 13 - Commitments and Contingencies - Performance Assurance.

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 September 30, 2011, $3.5 million in letters of credit and $4 million in borrowings were outstanding under this credit facility.  At December 31, 2010, $13.7 million in loans and $5.5 million in letters of credit were outstanding under this credit facility.

Long-term Debt:  On June 15, 2011, we issued $40 million of First Mortgage 5.89 percent Bonds, Series WW and $20 million of this amount was used to redeem the Series SS Bonds.  The Series WW bonds were issued to one purchaser, in a private placement transaction, under a shelf facility that was put in place on February 4, 2011.  The Series WW bond issuance was planned when we entered into a commitment with the purchaser on July 15, 2010 to issue $40 million of first mortgage bonds at 5.89 percent on June 15, 2011 in a private placement transaction.  The remaining proceeds are being used for our capital expenditures and for other corporate purposes.  The shelf facility allows us to issue up to an additional $60 million of first mortgage bonds directly to the purchaser through December 31, 2012.  Neither party has any obligation to issue or purchase the additional $60 million first mortgage bonds available under the shelf facility.

NOTE 12 - PENSION AND POSTRETIREMENT MEDICAL BENEFITS

The fair value of Pension Plan trust assets was $103.5 million at September 30, 2011 and $107.4 million at December 31, 2010. The unfunded accrued pension benefit obligation recorded on the Condensed Consolidated Balance Sheets was $19.5 million at September 30, 2011 and $21.1 million at December 31, 2010.

The fair value of Postretirement Plan trust assets was $18.4 million at September 30, 2011 and $18.4 million at December 31, 2010.  The unfunded accrued postretirement benefit obligation recorded on the Condensed Consolidated Balance Sheets was $6.1 million at September 30, 2011, and $6.8 million at December 31, 2010.

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

Pension Benefits	Three months ended September 30						Nine months ended September 30
	2011			2010			2011			2010
Service cost	$	1,142		$	1,026		$	3,426		$	3,078
Interest cost		1,851			1,754			5,553			5,262
Expected return on plan assets		(2,120	)		(2,063	)		(6,360	)		(6,189	)
Amortization of prior service cost		104			107			312			321
Amortization of net actuarial loss		60			0			180			0
Net periodic benefit cost		1,037			824			3,111			2,472
Less amounts capitalized		202			187			644			505
Net benefit costs expensed	$	835		$	637		$	2,467		$	1,967
Postretirement Benefits	Three months ended September 30						Nine months ended September 30
		2011			2010			2011			2010
Service cost	$	198		$	228		$	594		$	684
Interest cost		330			395			990			1,185
Expected return on plan assets		(357	)		(301	)		(1,071	)		(903	)
Amortization of transition obligation		64			64			192			192
Amortization of prior service cost		70			70			210			210
Amortization of net actuarial loss		51			242			153			726
Net periodic benefit cost		356			698			1,068			2,094
Less amounts capitalized		69			159			221			428
Net benefit costs expensed	$	287		$	539		$	847		$	1,666

Investment Strategy Our pension investment policy seeks to achieve sufficient growth to enable the Pension Plan to meet our future benefit obligations to participants, maintain certain funded ratios and minimize near-term cost volatility.  Current guidelines specify generally that approximately 38 percent of plan assets be invested in equity securities, 52 percent of plan assets be invested in debt securities and 10 percent of assets be invested in alternative investments.  The asset allocation guidelines will automatically adjust to predetermined levels as the plan’s funded status changes.  This approach is expected to reduce the risk of loss in the overall pension portfolio.  The debt securities are primarily comprised of long-duration bonds to match changes in plan liabilities.

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

Trust Fund Contributions:  In April 2011, we contributed $4.1 million to the pension trust fund and $0.2 million to the postretirement medical fund, and in June 2011 we contributed an additional $1.4 million to the postretirement medical fund.  In July 2010, we contributed $2.7 million to the pension trust fund and $3.3 million to the postretirement medical trust fund.

NOTE 13 - COMMITMENTS AND CONTINGENCIES

Long-Term Power Purchases Vermont Yankee:We are purchasing our entitlement share of Vermont Yankee plant output through the VY PPA between Entergy-Vermont Yankee and VYNPC.  We have one secondary purchaser that receives less than 0.5 percent of our entitlement.  See Note 4 – Investments in Affiliates for additional information on the VY PPA.

Entergy-Vermont Yankee has no obligation to supply energy to VYNPC over its entitlement share of plant output, so we receive reduced amounts when the plant is operating at a reduced level, and no energy when the plant is not operating.  We purchase replacement energy as needed when the Vermont Yankee plant is not operating or is operating at reduced levels.  We typically acquire most of this replacement energy through forward purchase contracts and account for those contracts as derivatives.  Our total VYNPC purchases were $16 million for the third quarter and $50.2 million for the nine months ended September 30, 2011 and $16.5 million for the third quarter and $42.9 million for the nine months ended September 30, 2010.

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On June 22, 2010, we, along with GMP, made a claim under the September 6, 2001 VY PPA.  The claim is 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.  We cannot predict the outcome of this matter at this time.

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

Our contract for power purchases from VYNPC ends in March 2012, but there is a risk that we could lose this resource if the plant shuts down for any reason before that date, and its future beyond that date is uncertain. An early shutdown could cause our customers to lose the economic benefit of an energy volume of close to 50 percent of our total committed supply and we would have to acquire replacement power resources for approximately 40 percent of our estimated power supply needs.  While this has been a significant concern in the past, the ever-shortening span of time before the contract’s end and changes in the regional power market have decreased the risk the company might face.  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. We are not able to predict whether there will be an early shutdown of the Vermont Yankee plant or whether the PSB would allow timely and full recovery of any costs related to such shutdown.

Under Vermont law, in addition to a favorable Vermont legislative vote, the PSB must issue a Certificate of Public Good in order for the plant to continue to operate after March 21, 2012.  On February 24, 2010, in a non-binding vote, the Vermont Senate voted against allowing the PSB to consider granting the Vermont Yankee plant another 20-year operating license.  On November 2, 2010 Vermont elected a new governor who continues to strongly advocate for the closure of the Vermont Yankee plant when its current license expires.

After the November election, Entergy announced it had begun pursuing a possible sale of the plant, apparently concluding that the plant had a better chance at remaining part of Vermont’s power supply under new ownership.  During this time, we vigorously engaged in contract talks with Entergy-Vermont Yankee for the specific purpose of increasing the chances the plant would continue to operate beyond 2012.  On March 29, 2011, Entergy announced its sale process had concluded unsuccessfully.  Consequently, the potential for state legislative and regulatory approval of continued plant operations is now, in our view, extremely low.  However, as discussed more fully below, Entergy-Vermont Yankee is seeking to operate the plant beyond March 21, 2012 without such approvals.

On March 10, 2011, the NRC voted 4-0 to approve the 20-year license extension through March 21, 2032 requested by Entergy-Vermont Yankee.  This approval removed the last federal-level regulatory requirement for relicensing of the Vermont Yankee station.

Entergy-Vermont Yankee, previously attempting to overcome legislative concerns, challenged the state’s authority as it relates to relicensing.  In a federal lawsuit filed on April 18, 2011, Entergy-Vermont Yankee contended that the state was improperly attempting to interfere with its relicensing.  In the complaint filed in U.S. District Court for the District of Vermont, Entergy-Vermont Yankee is seeking a judgment to prevent the state of Vermont from forcing the Vermont Yankee nuclear power plant to cease operation on March 21, 2012.  The complaint seeks both declaratory and injunctive relief, and contends that Vermont’s attempts to close the plant are preempted by the Atomic Energy Act, theFederal Power Act and the Commerce Clause of the U.S. Constitution.  The state of Vermont has vigorously defended its position.

On June 27, 2011, ISO-NE announced that studies have shown Vermont Yankee is “needed to support the grid’s ability to reliably meet demand in Vermont, southern New Hampshire and portions of Massachusetts, as well as reliability for the entire region’s power system.”

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On July 18, 2011, the U.S. District Court for the District of Vermont denied Entergy-Vermont Yankee’s motion for a preliminary injunction to enjoin the state from enforcing Vermont statutes that would require Vermont Yankee to cease operations after March 21, 2012.  In denying the motion, the court expressly declined to issue a holding regarding Entergy’s likelihood of success on the merits but noted that Entergy raised serious questions regarding its Atomic Energy Act preemption claim, which warrant further briefing and a “full-dress” trial on the merits.  The court also took judicial notice that on June 28, 2011, Standard & Poor’s affirmed Entergy Corporation’s corporate credit and issue ratings but revised its credit outlook from “stable” to “negative.”

On July 25, 2011, Entergy announced that its board of directors approved the refueling scheduled for October 2011, despite uncertainty about whether the Vermont Yankee plant will continue operations after March 21, 2012.  The refueling period ended November 3, 2011.  We purchased replacement power for this expected outage as discussed below in Future Power Agreements.

During the week of September 12, 2011, the U.S. District Court for the District of Vermont held a trial on the merits of Entergy-Vermont Yankee’s complaint.  At the end of September 2011, both parties filed final briefs for the court to consider before making its decision, which is expected in November 2011.

We are evaluating the potential impact of the litigation on our financial statements and on our customers.  The outcome of this matter is uncertain at this time.

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.  Our total purchases under the VJO Power contract were $15.3 million for the third quarter and $46.6 million for the nine months ended September 30, 2011 and $15.7 million for the third quarter and $47.4 million for the nine months ended September 30, 2010.

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

There are two sellback contracts with provisions that apply to existing and future VJO power contract purchases.  The first resulted in the sellback of 25 MW of capacity and associated energy through April 30, 2012, which has no net impact currently since an identical 25 MW purchase was made in conjunction with the sellback. We have a 23 MW share of the 25 MW sellback. However, since the sellback ends six months before the corresponding purchase ends, the first sellback will result in a 23 MW increase in our capacity and energy purchases for the period from May 1, 2012 through October 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 three 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 September 30, 2011, our obligation is about 47 percent of the total VJO power contract through 2016, and represents approximately $242.8 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 $283 million for the remainder of the contract, assuming that all members of the VJO defaulted by October 1, 2011 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.  These plants use water or biomass as fuel.  Most of the power comes through a state-appointed purchasing agent that allocates power to all Vermont utilities under PSB rules.  Our total purchases from IPPs were $4.7 million for the third quarter and $17.9 million for the first nine months of 2011 and $3.9 million for the third quarter and $16.1 million for the first nine months of 2010.

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 a need for additional decommissioning funding is necessary, we will be obligated to resume contributions to the Trust Fund.

We have equity ownership interests in Maine Yankee, Connecticut Yankee and Yankee Atomic.  These plants are permanently shut down and completely decommissioned except for the spent fuel storage at each location.  Our obligations related to these plants are described in Note 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 Millstone:  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.  A formal request to the DOE for payment has been made.  Payment is anticipated by the end of 2011.  Our share is approximately $0.2 million and will be credited to our retail customers.

We continue to pay our share of the DOE Spent Fuel assessment expenses levied on actual generation.

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.

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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.

The HQUS PPA will replace approximately 65 percent of the existing VJO power contract discussed above, which along with the VY PPA supply the majority of Vermont’s current power needs. The VJO power contract and the VY PPA expire within the next several years.

The obligations of HQUS and each Buyer are contingent upon the receipt of certain governmental approvals. 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. Technical hearings were held and final legal briefs were filed in the first quarter of 2011.  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:  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 our existing contract with Vermont Yankee.  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 when we had remaining supply gaps next year. 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 used the auction process to sell small amounts of projected excess energy in 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 $3.4 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 are currently selling power in the wholesale market pursuant to contracts with third parties, and are required to post collateral under certain conditions defined in the contracts.

At September 30, 2011, we had posted $4 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 $0.5 million of which was represented by cash and cash equivalents. At December 31, 2010, we had posted $6.6 million of collateral under performance assurance requirements for certain of our power and transmission transactions, $5.5 million of which was represented by a letter of credit and $1.1 million of which was represented by cash and cash equivalents.

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

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Environmental Overthe years, more than 100 companies have merged into or been acquired by CVPS.  At least two of those companies used coal to produce gas for retail sale.  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 $0.7 million as of September 30, 2011 and $0.8 million as of December 31, 2010.  The reserve for environmental matters is included as current and long-term liabilities on the Condensed Consolidated Balance Sheets and represents our best estimate of the cost to remedy issues at these sites based on available information as of the end of the applicable reporting periods.  Below is a brief discussion of the significant sites for which we have recorded reserves.

Cleveland Avenue Property: The Cleveland Avenue property in Rutland, Vermont, was used by a predecessor to make gas from coal.  Later, we sited various operations there.  Due to the existence of coal tar deposits, PCB contamination and the potential for off-site migration, we conducted studies in the late 1980s and early 1990s to quantify the nature and extent of contamination and potential costs to remediate the site.  Investigation at the site continued, including work with the State of Vermont to develop a mutually acceptable solution.  In June 2010, both the VANR and the EPA approved separate remediation work plans for the manufactured gas plant and PCB waste at the site.  Remedial work started in August 2010 and concluded in early December 2010.  It was necessary to increase the reserve by $0.3 million in the first quarter of 2011.  In February 2011, we submitted a Construction Completion Report for the project to the EPA and VANR for review.  The report documented remedial construction and confirmatory sampling activities.  Some additional sitework including final grading and vegetation planting occurred during the third quarter.  As of September 30, 2011, there was no remaining obligation.

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 September 30, 2011, our estimate of the remaining obligation is $0.5 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.

In 2010, we discussed the proposed redevelopment with consultants for the Town of Brattleboro and the Windham Regional Commission. We have expressed our willingness to enter into a formal remediation agreement with the Town of Brattleboro governing the redevelopment to assure continued acknowledgement of site contamination. We received a non-binding letter from the Town of Brattleboro summarizing its preferred remedial plan.

We met with the Town of Brattleboro in June 2011 and learned they expect to complete the gas plant site and waterfront project in 2011.  In late September, we agreed with the Town of Brattleboro on language for an Amended and Restated Grant of Environmental Restrictions for the gas plant property. Once Brattleboro officials sign and record this grant, we will contribute $0.2 million, which is our share of funding for the project.  Subsequently, we will reassess the reserve and need, if any, for a revised probabilistic cost estimate for site remediation.

Dover, New Hampshire, Manufactured Gas Facility: In 1999, PSNH contacted us about this site.  PSNH alleged that we were partially liable for cleanup, since the site was previously operated by Twin State Gas and Electric, which merged into CVPS on the same day that PSNH bought the facility.  In 2002, we reached a settlement with PSNH in which certain liabilities we might have had were assigned to PSNH in return for a cash settlement we paid based on completion of PSNH’s cleanup effort.  As of September 30, 2011, our estimate of the remaining obligation is less than $0.1 million.

Middlebury Lower Substation: By letter dated February 5, 2010, the VANR Sites Management Section informed us they require additional investigation of the soil contamination at the Middlebury Lower Substation.  This was a result of voluntarily submitted information from internal soil sampling that we completed in the fall of 2009.  The soil sampling showed elevated levels of TPH that required remediation.  The contaminated soil and concrete was removed in conjunction with the reconstruction of the substation.  As of September 30, 2011, our estimate of the remaining obligation is less than $0.1 million.

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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 site.  The substation is located adjacent to the Salisbury hydroelectric power station.  It is scheduled to be retired and replaced during 2011.  Final results indicated that PCB, TPH and pesticide concentrations exceed state and federal regulatory limits at portions at the site.  We submitted a letter to the VANR Sites Management Section proposing that PCB remediation efforts would be sufficient mitigation for TPH and pesticide contamination, and proposed to collect soil samples for confirmatory testing of these compounds.  Remediation is expected to be completed in the fourth quarter of 2011.  As of September 30, 2011, our estimate of the remaining obligation is $0.2 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.

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 September 30, 2011 is approximately $0.4 million. The total future minimum lease payments required for all lease schedules under this agreement at September 30, 2011 is $2.6 million.  As of September 30, 2011 there is no credit line in place for additions under this agreement. The total acquisition cost of all lease additions under this agreement at September 30, 2011 was $5.3 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 September 30, 2011 is $1.8 million. As of September 30, 2011 there is no credit line in place for additions under this agreement.  The total acquisition cost of all lease additions under this agreement at September 30, 2011 was $2.9 million.

Merger Agreement with Gaz Métro 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 pay Gaz Métro a termination fee of $17.5 million and reimburse Gaz Métro for up to $2 million of its reasonable out-of-pocket transaction expenses.  Also, see Note 2 - Summary of Significant Accounting Policies to the accompanying Notes to Condensed Consolidated Financial Statements.

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.

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NOTE 14 – ACQUISITIONS

Vermont Marble Power Division:  On April 30, 2010, we signed a purchase and sale agreement with Omya to purchase certain generating, transmission and distribution assets of Vermont Marble located in the State of Vermont.  Under this agreement, we would pay approximately $33.2 million for the transmission and distribution assets and generating assets comprised of four hydroelectric generating stations.  The agreement contains usual and customary purchase and sale terms and conditions and is contingent upon federal and state regulatory approvals.

With Omya, we filed a joint petition with the PSB on August 2, 2010, requesting that they consent to the proposed sale by Omya and purchase by us of assets used in the public service business of Vermont Marble and approve certain related matters.

An application for approval of the proposed transaction was filed with FERC on August 31, 2010.  We received approval, subject to certain conditions, on October 28, 2010.

On February 25, 2011, we filed with the PSB an MOU between us, the DPS, the Town of Proctor and Omya, that resolves all the outstanding issues between the parties concerning our acquisition of Vermont Marble. We will be allowed recovery from customers of $27 million for the generating assets and the $1 million for the transmission and distribution assets.  The MOU also requires the creation of a so-called value sharing pool that provides for certain excess value we receive, if any, to be shared among our customers, Omya and our shareholders if energy market prices and hydro facility improvements create more value than anticipated for a period of 15 years following the closing date.   This will provide us with an opportunity to recover the $1.3 million not otherwise recovered in rates.

The agreement also includes a five-year, six-step phase-in of residential rate changes for existing Vermont Marble customers, which will be funded by Omya up to an amount estimated to be approximately $1.1 million.

On March 4, 2011, we signed an amended and restated purchase and sale agreement with Omya to incorporate the terms of the MOU filed on February 25, 2011.  The PSB held a hearing on the matter on April 11, 2011 and on June 10, 2011 the PSB issued an order approving the purchase and sale agreement, and issued a Certificate of Consent.

Included in the sale are rights to serve approximately 875 customers, including the Omya industrial facility, which became our single-largest customer representing approximately 6 percent of annual retail sales.

We plan to invest an estimated $20 million between 2012 and 2015 to upgrade the Vermont Marble facilities.

We acquired Vermont Marble to promote the general good of the state; the acquisition will create efficiencies that will benefit customers overall, and is consistent with the 2005 State of Vermont electric plan.

In the first nine months of 2011, we incurred $0.1 million of acquisition-related costs that were recorded in the Condensed Consolidated Statements of Operations.  On September 1, 2011, we closed on the transaction. The actual revenues of Vermont Marble from the acquisition date through September 30, 2011 were approximately $1.6 million.  If the Vermont Marble acquisition closed on January 1, 2010, the incremental revenues would have been $4 million and $12.2 million for the three and nine month periods ended September 30, 2010 and approximately $4.7 million and $14.2 million for the three and nine month periods ended September 30, 2011.

Our primary valuation technique to measure the fair value of the assets shown below at the acquisition date is based on the income approach.  This is due to the regulatory treatment of utility-related assets.

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The fair value allocations of the Vermont Marble acquisition completed in the third quarter of 2011 are as follows (dollars in thousands):

	Vermont Marble
Fair value of business combination:
Cash payments	$	29,345
Total	$	29,345
Identifiable assets acquired:
Utility plant, at original cost, net of accumulated depreciation	$	29,081
Investments in affiliates		2
Accounts receivable, less allowance for uncollectible accounts ($17)		151
Other deferred charges - regulatory		658
Other deferred charges and other assets		111
Total	$	30,003
Liabilities Assumed:
Power-related derivatives	$	658
Total	$	658

We are reporting the operations for this acquisition within the results of our CV-VT segment from the acquisition date.

Readsboro Electric Department:  On October 27, 2010, we signed a purchase and sale agreement with Readsboro.  The $0.4 million purchase price includes all of the assets of Readsboro including about 14 miles of distribution line and associated equipment, and the exclusive franchise Readsboro holds to serve its 310 customers.  On February 24, 2011 we, along with the DPS and Readsboro, filed a stipulation with the PSB that resolves the issues outstanding in our acquisition of Readsboro.  On July 8, 2011, the PSB issued an order approving the purchase and sale agreement, and issued a Certificate of Consent.  The PSB order does not allow us to recover the acquisition premium of $0.1 million, which is the amount above the net book value of $0.3 million, which approximates fair value.  We also assumed a nominal amount of liabilities.  On August 1, 2011, we closed on the transaction.

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NOTE 15- SEGMENT REPORTING

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

	CV-VT			Unregulated Companies		Reclassification  & Consolidating Entries			Consolidated
Three Months Ended
September 30, 2011
Revenues from external customers	$	88,051		$	430	$	(430	)	$	88,051
Net (loss) income	$	(8,670	)	$	24				$	(8,646	)
Total assets at September 30, 2011	$	749,100		$	2,887	$	(201	)	$	751,786
September 30, 2010
Revenues from external customers	$	85,392		$	438	$	(438	)	$	85,392
Net income	$	9,921		$	69				$	9,990
Total assets at December 31, 2010	$	707,973		$	3,019	$	(246	)	$	710,746
Nine Months Ended
September 30, 2011
Revenues from external customers	$	269,404		$	1,280	$	(1,280	)	$	269,404
Net income	$	371		$	144				$	515
Total assets at September 30, 2011	$	749,100		$	2,887	$	(201	)	$	751,786
September 30, 2010
Revenues from external customers	$	256,336		$	1,306	$	(1,306	)	$	256,336
Net income	$	15,456		$	181				$	15,637
Total assets at December 31, 2010	$	707,973		$	3,019	$	(246	)	$	710,746

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

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

Forward-Looking Statements Statements contained in this report that are not historical fact are forward-looking statements within the meaning of the ‘safe-harbor’ provisions of the Private Securities Litigation Reform Act of 1995.  Whenever used in this report, the words “estimate,” “expect,” “believe,” 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;

§ the performance and continued operation of the Vermont Yankee nuclear power plant;

§ changes in the cost or availability of capital;

§ our ability to replace or renegotiate our long-term power supply contracts;

§ effects of and changes in local, national and worldwide economic conditions;

§ effects of and changes in weather;

§ volatility in wholesale power markets;

§ our ability to maintain or improve our current credit ratings;

§ the operations of ISO-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 in Part I, Item 1A, Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2010.

EXECUTIVE SUMMARY

The results of our operations for the third quarter of 2011 were a net loss of $8.6 million, or 65 cents per diluted share of common stock, and net income of $0.5 million, or 2 cents per diluted share for the first nine months of 2011.  This compares to consolidated earnings for the third quarter of 2010 of $10 million, or 79 cents per diluted share of common stock, and $15.6 million, or $1.27 cents per diluted share for the first nine months of 2010.  The primary drivers of the year-over-year earnings variances are described below.

Tropical Storm Irene:  On August 28, 2011, Tropical Storm Irene severely impacted the northeast, including our service territory, resulting in approximately 73,000 CVPS customer outages.  In preparation for the storm, we secured outside utility and tree crews from as far away as Illinois, Missouri, Texas and Canada, and we restored power to our last customer on September 2, 2011.  As of September 30, 2011, estimated storm costs were $9.9 million and we had $0.9 million of related capital expenditures.  Of the $9.9 million costs, $8.8 million were deferred and will be recovered in future rates, beginning on July 1, 2012, under the exogenous cost provision of our alternative regulation plan.  See Results of Operations below for more discussion about the impact on our financial statements.

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Pending merger-related costs: As of September 30, 2011, we incurred $26.6 million in merger-related costs, or $1.17 after tax per diluted share of common stock.

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

Acquisitions:  This quarter, we also expanded our service territory and acquired the Readsboro Electric Department and Vermont Marble Power Division of Omya, Inc.  See Liquidity, Acquisitions below for additional information.

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

PENDING MERGER

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, FERC and the PSB; and the absence of any governmental action challenging or seeking to prohibit 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 pay Gaz Métro a termination fee of $17.5 million and reimburse Gaz Métro for up to $2 million of its reasonable out-of-pocket transaction expenses.

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.

In addition, we made other regulatory filings seeking approval of the proposed merger, including with the Nuclear Regulatory Commission, the Federal Energy Regulatory Commission, the Federal Trade Commission, Federal Communications Commission, 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 proposed merger.

Shareholder Approval:  On September 29, 2011, CVPS held a Special Meeting of Shareholders (“Special Meeting”), in Rutland, Vermont.  The shareholders approved the Agreement and Plan of Merger, effective as of July 11, 2011, in a non-binding advisory vote and approved the change-in-control payments related to the merger.  Over 75 percent of the outstanding shares of the company were represented at the meeting, and of those, more than 97 percent voted in support of the sale. 

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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 (“Merger Sub”) 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”), including the termination fee of $17.5 million and expenses of FortisUS Inc. of $2 million. These amounts have been recorded to Other deductions on the Condensed Consolidated Statement of Operations in the three-month period ended September 30, 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 reimburse Gaz Métro for the full amount of the Fortis Termination Payment 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.

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.

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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 Gaz Métro merger were misleading and/or incomplete, and that the CVPS Board had violated its fiduciary duties.  The proposed consolidated amended complaint also contains claims for aiding and abetting fiduciary breaches against CVPS and Gaz Métro.  The proposed consolidated amended complaint seeks, 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.

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 proposed Gaz Métro 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 proposed 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. The parties to the Davis action have informed the court of the memorandum of understanding and will be seeking court approval of the proposed settlement. The parties to the MOU reserved their rights with respect to the determination of plaintiffs’ attorneys fees, if any, when our settlement agreement is reviewed by the court.

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, contains 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.

On October 14, 2011, CVPS and the other defendants filed motions to dismiss the federal IBEW complaint.

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RETAIL RATES AND ALTERNATIVE REGULATION

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 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 shortfall 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 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 the third quarter of 2011, we deferred $8.6 million of costs related to Tropical Storm Irene and legislative tax law changes.  We plan to file with the PSB by 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 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 2010 return on equity from the regulated portion of our business was 8.95 percent. We filed this calculation with the PSB in April 2011. No ESAM adjustment was required since this return was within 75 basis points of our 2010 allowed return on equity of 9.59 percent.  On May 20, 2011 the DPS notified the PSB that they agreed with our conclusion that an adjustment for the 2010 ESAM was not required.  On May 26, 2011 the PSB accepted our 2010 ESAM calculation.

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 will be collected from customers over the three months ending March 31, 2012. We filed a PCAM report with the PSB identifying this under-collection.  The PSB has not yet acted on this filing.

The PCAM adjustment for the second quarter of 2011 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 December 31, 2011. We filed a PCAM report with the PSB identifying this over-collection.  The DPS recommended the PCAM report be approved as filed and the PSB accepted the DPS recommendation and approved the filing.

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 proposes 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.  The base rate filing will become effective January 1, 2012 unless suspended by the PSB.  We cannot predict the outcome of this matter at this time.

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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.  As a participant on Vermont’s smart grid stimulus application, we expect to receive a grant of over $31 million.

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 eligible to receive reimbursement of 50 percent of our total project costs incurred since August 6, 2009, up to $31 million.  From the inception of the project through September 30, 2011, we have incurred $10.7 million of costs, of which $6.6 million were operating expenses and $4.1 million were capital expenditures.  In the third quarter of 2011, we recorded $3.1 million to various operating expenses and $4.2 million was recorded in the first nine months.

We have submitted requests for reimbursement of $5 million and have received $3.4 million to date, of which $1.1 million was received in 2011.

On July 19, 2011, we entered into a contract for the communications infrastructure in support of our advanced metering project.  The overall contract is approximately $6.2 million for which we are jointly and severally liable with another party.  Our share of the contract cost is approximately $3.9 million.  The contract calls for a $1.9 million initial payment with remaining payments for certain milestones to be made over a two-year period.  In August 2011, we made the initial payment of $1.9 million and submitted this payment to the DOE for 50 percent reimbursement.

Pending Merger with Gaz Métro  Also, see Pending Merger, Regulatory approvals above.

LIQUIDITY, CAPITAL RESOURCES AND COMMITMENTS

Cash Flows At September 30, 2011, we had cash and cash equivalents of $1.7 million compared to $3.9 million at September 30, 2010.

Our primary sources of cash in 2011 were from our electric utility operations, distributions received from affiliates, income tax refunds, reimbursements from restricted cash of debt-financed project costs, borrowings under our revolving credit facility, net proceeds from the issuance of long-term debt and the Fortis Termination Payment reimbursement from Gaz Métro.  Our primary uses of cash in 2011 included the Fortis Termination Payment and merger-related costs, acquisitions of Vermont Marble and Readsboro utility property, capital expenditures, common and preferred stock dividend payments, repayments of borrowings under our revolving credit facility and long-term debt, employee benefit plan funding, and working capital requirements.

Operating Activities: Operating activities provided $41.7 million in cash in the first nine months of 2011, compared to $38 million in 2010.  The increase of $3.7 million was primarily due to: a $19.5 million Termination Payment reimbursement from Gaz Métro, a $4.6 million increase in net income tax refunds; a $3.2 million increase in distributions received from affiliates; a $1.1 million recovery of bad debt expense and a $10.7 million increase in working capital and other operating activities.  This was partially offset by a $19.5 million Termination Payment to Fortis, a $6.5 million decrease in special deposits and restricted cash, including a $5.4 million decrease in special deposits in 2010 due to replacing purchased power cash collateral with a letter of credit, a decrease of $7.1 million used for merger-related costs, and a decrease of $2.3 million related to major storm costs.

At September 30, 2011, our retail customers’ accounts receivable over 60 days totaled $2.7 million compared to $2.6 million at December 31, 2010, which was an increase of 3.2 percent.

Investing Activities: Investing activities used $43.7 million in the first nine months of 2011, compared to $21.6 million in 2010.  The increase of $22.1 million used is due to: an increase of $29.7 million for the acquisition of Vermont Marble and Readsboro utility property, an increase of $6.4 million for construction and plant expenditures.  The majority of the construction and plant expenditures were for system reliability, performance improvements and customer service enhancements, partially offset by $13 million of reimbursements of restricted cash related to capital projects, and a $0.9 million increase in reimbursements from the DOE relating to the CVPS SmartPower® project.

Financing Activities: Financing activities provided $1 million in the first nine months of 2011, compared to a use of $14.5 million in 2010.  The increase of $15.6 million is due to: a $40 million increase in long-term borrowings, and a $13.6 million decrease in net credit facility repayments partially offset by a $20 million increase in repayment of long-term debt, a $0.9 million increase in common stock dividends paid, and a $17.1 million decrease in net proceeds from the issuance of common stock.

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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, $0 in 2013, $23.3 million in 2014 and $24 million in 2015, but the timing and amounts depend on the factors discussed above and the amounts invested by other owners.

Any investments that we make in Transco are voluntary, and subject to available capital and appropriate regulatory approvals.  These capital investments in Transco and our core business provide value to customers and shareholders alike.  They provide shareholders with a return on investment while helping to maintain and improve reliability for our customers.

Acquisitions Vermont Marble Power Division:  On April 30, 2010, we signed a purchase and sale agreement with Omya to purchase certain generating, transmission and distribution assets of Vermont Marble located in the State of Vermont.  Under this agreement, we would pay approximately $33.2 million for the transmission and distribution assets and generating assets comprised of four hydroelectric generating stations.  The agreement contains usual and customary purchase and sale terms and conditions and is contingent upon federal and state regulatory approvals.

With Omya, we filed a joint petition with the PSB on August 2, 2010, requesting that they consent to the proposed sale by Omya and purchase by us of assets used in the public service business of Vermont Marble and approve certain related matters.

An application for approval of the proposed transaction was filed with FERC on August 31, 2010.  We received approval, subject to certain conditions, on October 28, 2010.

On February 25, 2011, we filed an MOU between us, the DPS, the Town of Proctor and Omya, with the PSB that resolves all the outstanding issues between the parties concerning our acquisition of Vermont Marble. We will be allowed recovery from customers of $27 million for the generating assets and the $1 million for the transmission and distribution assets.  The MOU also requires the creation of a so-called value sharing pool that provides for certain excess value we receive, if any, to be shared among our customers, Omya and our shareholders if energy market prices and hydro facility improvements create more value than anticipated for a period of 15 years following the closing date.   This will provide us with an opportunity to recover the $1.3 million not otherwise recovered in rates.

The agreement also includes a five-year, six-step phase-in of residential rate changes for existing Vermont Marble customers, which will be funded by Omya up to an amount estimated to be approximately $1.1 million.

On March 4, 2011, we signed an amended and restated purchase and sale agreement with Omya to incorporate the terms of the MOU filed on February 25, 2011.  The PSB held a hearing on the matter on April 11, 2011 and on June 10, 2011 the PSB issued an order approving the purchase and sale agreement, and issued a Certificate of Consent.

Included in the sale are rights to serve approximately 875 customers, including the Omya industrial facility, which became our single-largest customer representing approximately six percent of annual retail sales.

We plan to invest an estimated $20 million between 2012 and 2015 to upgrade the Vermont Marble facilities.

We acquired Vermont Marble to promote the general good of the state; the acquisition will create efficiencies that will benefit customers overall, and is consistent with the 2005 State of Vermont electric plan.

In the first nine months of 2011, we incurred $0.1 million of acquisition-related costs that were recorded in the Condensed Consolidated Statements of Operations.  On September 1, 2011, we closed on the transaction. The actual revenues of Vermont Marble from the acquisition date through September 30, 2011 were approximately $1.6 million.  If the Vermont Marble acquisition closed on January 1, 2010, the incremental revenues would have been $4 million and $12.2 million for the three and nine month periods ended September 30, 2010 and approximately $4.7 million and $14.2 million for the three and nine month periods ended September 30, 2011.

Readsboro Electric Department:  On October 27, 2010, we signed a purchase and sale agreement with Readsboro.  The $0.4 million purchase price includes all of the assets of Readsboro including about 14 miles of distribution line and associated equipment, and the exclusive franchise Readsboro holds to serve its 310 customers.  On February 24, 2011 we, along with the DPS and Readsboro, filed a stipulation with the PSB that resolves the issues outstanding in our acquisition of Readsboro.  On July 8, 2011, the PSB issued an order approving the purchase and sale agreement, and issued a Certificate of Consent.    The PSB order does not allow us to recover the acquisition premium of $0.1 million, which is the amount above the net book value of $0.3 million, which approximates fair value.  We also assumed a nominal amount of liabilities.  On August 1, 2011, we closed on the transaction.

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Preferred Stock In accordance with the terms of the Merger Agreement, we plan to redeem all outstanding shares of our preferred stock 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 Vermont Yankee plant outage or similar event could significantly impact our liquidity due to the potentially high cost of replacement power and performance assurance requirements arising from purchases through ISO-NE or third parties.  While this has been a significant concern in the past, the ever-shortening span of time before the contract’s end and changes in the regional power market have decreased any risk we may face.  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.  An extended unplanned Vermont Yankee plant outage could involve cost recovery under the PCAM but in general would not be expected to materially impact our financial results, if the costs are recovered in retail rates in a timely fashion.

Other material risks to cash flow from operations include: loss of retail sales revenue from unusual weather; slower-than-anticipated load growth and unfavorable economic conditions; significant storm recovery costs; increases in net power costs largely due to lower-than-anticipated margins on sales revenue from excess power or an unexpected power source interruption; required prepayments for power purchases; and increases in performance assurance requirements.  It is important to note, however, that our alternative regulation plan 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.  Our obligations under the Credit Agreement are guaranteed by our wholly owned, unregulated subsidiaries, C.V. Realty and CRC.  The purpose of the facility is to provide liquidity for general corporate purposes, including working capital and power contract performance assurance requirements, in the form of funds borrowed and letters of credit.  At September 30, 2011, $3.5 million in letters of credit and $4 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.  This facility replaced a 364-day, $15 million unsecured revolving credit facility that matured on December 29, 2010.  The purpose and obligation under this credit agreement are the same as described above.  At September 30, 2011, there were no loans or letters of credit outstanding under this credit facility.  We have not used this facility for borrowings or letters of credit during the first nine months of 2011.

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First Mortgage Bonds:   On June 15, 2011, we issued $40 million of First Mortgage 5.89 percent Bonds, Series WW and $20 million of this amount was used to redeem the Series SS Bonds.  The Series WW bonds were issued to one purchaser, in a private placement transaction, under a shelf facility that was put in place on February 4, 2011.  The Series WW bond issuance was planned when we entered into a commitment with the purchaser on July 15, 2010 to issue $40 million of first mortgage bonds at 5.89 percent on June 15, 2011 in a private placement transaction, pending regulatory approvals.  The proceeds are being used to help finance our capital expenditures, debt retirements, utility acquisitions and other corporate purposes.  The shelf facility allows us to issue up to an additional $60 million of first mortgage bonds directly to the purchaser through December 31, 2012.  Neither party has any obligation to issue or purchase the additional $60 million first mortgage bonds available under the shelf facility.

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 September 30, 2011, 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.  As of September 30, 2011, capital expenditures were $27.4 million.

Capital expenditures for the years 2011 to 2014 are expected to range from $42 million to $69 million annually, including an estimated total of more than $60 million for CVPS SmartPower® over the four-year period.  A portion of this CVPS SmartPower® project total will be funded by the Smart Grid Stimulus Grant and this grant has reduced the 2011 to 2014 estimated spending range above.  Further discussion of the Smart Grid Stimulus Grant can be found above in Retail Rates and Alternative Regulation - CVPS SmartPower®.

Contractual Obligations CVPS SmartPower®: On April 14, 2011, we entered into a contract for approximately $28.8 million related to our CVPS SmartPower® program for the purchase of our advanced metering infrastructure.  We expect to make payments for certain milestones over a two-year period and will seek reimbursement from the DOE for approximately 50 percent of eligible project costs under the eEnergy Vermont SmartGrid Investment Grant.

On July 19, 2011, we entered into a contract for the communications infrastructure in support of our advanced metering project.  The overall contract is approximately $6.2 million for which we are jointly and severally liable with another party.  Our share of the contract cost is approximately $3.9 million.  The contract calls for a $1.9 million initial payment with remaining payments for certain milestones to be made over a two-year period.  In August 2011, we made the initial payment of $1.9 million and submitted this payment to the DOE for 50 percent reimbursement.

Long-term Debt:  On June 15, 2011, we issued $40 million of First Mortgage 5.89 percent Bonds, Series WW and $20 million was used to redeem the Series SS Bonds.  See Financing above for additional information.

Merger Transaction Costs:  During the first nine months of 2011, we incurred merger-related costs of $26.6 million related to the merger agreements with Fortis and Gaz Métro.  We estimate additional costs of $1.1 million in the last quarter of 2011 and $4.5 million during the first six months of 2012.

See Pending Merger above for additional information related to a $19.5 million payment we made to Fortis in July 2011, related to the terminated merger agreement fees and expenses, and subsequent reimbursement from Gaz Métro.

For income tax purposes, we are currently deducting all merger transaction costs until such time as the merger is approved by the PSB.  At that time, the transaction costs that are facilitative in nature and therefore not deductible will be subject to income tax expense.

Other Future Power Agreements:  On July 27, 2011, in cooperation with an energy management firm, we conducted a highly structured Internet auction that involved a dozen pre-screened north-eastern 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.

The 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.  See Power Supply Matters below for additional information.

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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.

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 $3.4 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 are currently selling power in the wholesale market pursuant to contracts with third parties, and are required to post collateral under certain conditions defined in the contracts.

At September 30, 2011, we had posted $4 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 $0.5 million of which was represented by cash and cash equivalents. At December 31, 2010, we had posted $6.6 million of collateral under performance assurance requirements for certain of our power and transmission transactions, $5.5 million of which was represented by a letter of credit and $1.1 million of which was represented by cash and cash equivalents.

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

Off-balance-sheet arrangements We do not use off-balance-sheet financing arrangements, such as securitization of receivables, nor obtain access to assets through special purpose entities.  We have $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.  Until the third quarter of 2010, we leased most vehicles and related equipment under operating lease agreements; however, in the later part of 2010, we started to purchase most vehicles and related equipment.  These operating lease agreements are described in Note 13 - Commitments and Contingencies.

Commitments and Contingencies

Power Supply Matters: We have material power supply commitments for the purchase of power from VYNPC 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 and are obligated to pay a portion of VYNPC’s operating costs under the VY PPA between VYNPC and Entergy-Vermont Yankee.  We also own equity interests in three nuclear plants that have completed decommissioning.  We are responsible for paying our share of the costs associated with these plants.  Our equity ownership interests are described in Note 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.

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 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.  Also, see “Item 1. Legal Proceedings”.

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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 the key risks.

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

Regulatory Risk: Historically, electric utility rates in Vermont have been based on a utility’s costs of service.  Accordingly, we are entitled to charge rates that are sufficient to allow us an opportunity to recover reasonable operation and capital costs and a reasonable return on investment to attract needed capital and maintain our financial integrity, while also protecting relevant public interests.  We are subject to certain accounting standards that allow regulated entities, in appropriate circumstances, to establish regulatory assets and liabilities, and thereby defer the income statement impact of certain costs and revenues that are expected to be realized in future rates.  There is no assurance that the PSB will approve the recovery of all costs incurred for the operation, maintenance, and construction of our regulated assets, as well as a return on investment.  Adverse regulatory changes could have a significant impact on future results of operations and financial condition.  See Critical Accounting Policies and Estimates 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: Our contract for power purchases from VYNPC ends in March 2012, but there is a risk that the plant could be shut down earlier than expected if Entergy-Vermont Yankee determines that it is not economical to continue operating the plant, or due to environmental concerns. While this has been a significant concern in the past, the ever-shortening span of time before the contract’s end and changes in the regional power market have decreased the risk the company might face.  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 19 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: Our material power supply contracts are with Hydro-Québec and VYNPC.  These contracts comprise the majority of our total annual MWh purchases.  If one or both of these sources becomes unavailable for a period of time, there could be exposure to high wholesale power prices and that amount could be material.

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.

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 third quarter and first nine months of 2011.  This should be read in conjunction with the Condensed Consolidated Financial Statements and accompanying notes included in this report.

Results of Operations for the third quarter of 2011 decreased $18.6 million, or $1.44 per diluted share of common stock, compared to the same period in 2010.  Results of Operations for the first nine months of 2011 decreased $15.1 million, or $1.25 per diluted share of common stock, compared to the same period in 2010.

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The table that follows provides a reconciliation of the primary year-over-year variances in diluted EPS for the third quarter and first nine months of 2011 versus 2010.  The (loss) earnings per diluted share for each variance shown below are non-GAAP measures:

Reconciliation of Earnings (Losses) Per Diluted Share
	Third Quarter			First Nine Months
	2011 vs. 2010			2011 vs. 2010
2010 Earnings per diluted share	$	0.79		$	1.27
Major Statement of Operations Variances:
Higher operating revenue - retail sales volume		0.02			0.06
Merger-related fees		(1.03	)		(1.17	)
2010 Exogenous cost deferral, net of costs incurred (major storm in February 2010)		(0.16	)		0.00
Variable life insurance		(0.06	)		(0.03	)
Property taxes
Other (includes impact of additional common shares, income tax adjustments, and various items)		(0.21	)		(0.11	)
2011 (Loss) earnings per diluted share	$	(0.65	)	$	0.02

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

	Three months ended September 30								Nine months ended September 30
	Revenues								Revenues
	(in thousands)				MWh Sales				(in thousands)				MWh Sales
	2011		2010		2011		2010		2011		2010		2011		2010
Residential	$	37,874	$	36,243		234,642		242,076	$	116,793	$	108,718		735,210		728,369
Commercial		30,482		29,023		219,687		222,655		87,067		82,240		622,811		627,342
Industrial		9,759		8,002		106,816		90,987		28,108		24,967		292,973		274,281
Other		528		498		1,651		1,645		1,571		1,488		4,891		4,874
Total retail sales		78,643		73,766		562,796		557,363		233,539		217,413		1,655,885		1,634,866
Resale sales		4,973		8,299		142,180		172,659		22,412		26,622		574,399		555,963
Provision for rate refund		1,318		18		0		0		4,876		2,344		0		0
Other operating revenues		3,117		3,309		0		0		8,577		9,957		0		0
Total operating revenues	$	88,051	$	85,392		704,976		730,022	$	269,404	$	256,336		2,230,284		2,190,829

2011 vs. 2010

Operating revenues increased by $2.7 million for the third quarter and $13.1 million for the first nine months of 2011 compared to the same period in 2010 due to the following factors:

§ Retail sales increased $4.9 million for the third quarter and $16.1 million for the first nine months of 2011 resulting primarily from a 7.46 percent base rate increase effective January 1, 2011 and the acquisition of Vermont Marble on September 1, 2011, including the Omya industrial facility, our single-largest customer representing approximately 6 percent of retail sales.  In the third quarter, higher usage from Omya was offset by lower customer usage due to a cooler summer and the impacts of Tropical Storm Irene.  In the first nine months, higher customer usage was due to Omya sales and the colder winter and spring weather.

§ Resale sales decreased $3.3 million for the third quarter and $4.2 million for the first nine months of 2011 due to lower 2011 contract prices associated with the sale of our excess energy and lower volume available for resale due to higher retail load.

§ The provision for rate refund increased $1.3 million for the third quarter and $2.5 million for the first nine months of 2011 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 increase included the favorable impact of $4.9 million of net deferrals and refunds in 2011 vs. the favorable impact of $2.3 million of net deferrals and refunds in 2010.

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§ Other operating revenues decreased $0.2 million for the third quarter and $1.3 million for the first nine months of 2011 mostly due to a higher level of mutual aid for other utilities in 2010.

Operating Expenses Operating expenses increased $6.9 million in the third quarter and $13.5 in the first nine months of 2011 as compared to 2010.  Significant variances in operating expenses on the Condensed Consolidated Statements of Operations as described below.

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

	Three Months Ended September 30										Nine Months Ended September 30
	Purchases										Purchases
	(in thousands)						MWh purchases				(in thousands)						MWh purchases
	2011			2010			2011		2010		2011			2010			2011		2010
VYNPC	$	15,993		$	16,469			364,415		381,879	$	50,156		$	42,858			1,143,843		1,004,045
Hydro-Quebec		15,323			15,701			226,463		239,308	$	46,560			47,449			699,933		728,773
Independent Power Producers		4,696			3,899			39,795		31,314	$	17,921			16,056			150,268		135,290
Subtotal long-term contracts		36,012			36,069			630,673		652,501		114,637			106,363			1,994,044		1,868,108
Other purchases		1,671			4,861			10,903		40,212	$	3,681			13,716			13,327		146,276
Reserve for loss on power contract		(299	)		(299	)		0		0	$	(897	)		(897	)		0		0
Nuclear decommissioning		354			348			0		0	$	1,059			1,031			0		0
Other		125			130			0		0	$	513			(175	)		0		0
Total purchased power	$	37,863		$	41,109			641,576		692,713	$	118,993		$	120,038			2,007,371		2,014,384

2011 vs. 2010

Purchased power expense decreased $3.2 million for the third quarter and $1 million for the first nine months of 2011 compared to the same period in 2010 due to the following factors:

§ Purchased power costs under long-term contracts decreased $0.1 million in the third quarter and increased $8.3 million in the first nine months of 2011, due primarily to higher output at the Vermont Yankee plant and increased purchases from Independent Power Producers.

§ Other purchases decreased $3.2 million in the third quarter and $10 million in the first nine months of 2011 due to lower capacity costs and decreased volumes.

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

§ Other costs decreased by less than $0.1 million in the third quarter and increased $0.7 million in the first nine months of 2011. These Other costs are amortizations and deferrals based on PSB-approved regulatory accounting, including those for incremental energy costs related to Millstone Unit #3 scheduled refueling outages and deferrals for our share of nuclear insurance refunds received by VYNPC.

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 $6.1 million for the third quarter and $8.6 million for the first nine months was principally due to higher VTA billings due to higher cost of service and specific facility charges, partially offset by higher NOATT reimbursements under the VTA.

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 $4.7 million for the third quarter and the decrease of $2.4 million in the first nine months were primarily due to $8.6 million of exogenous costs recorded in the third quarter of 2011 vs. $3.6 million of exogenous costs recorded in the third quarter of 2010, and $3.2 million of lower net regulatory deferrals and amortizations recorded in the first nine months.

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Maintenance:  These expenses are associated with maintaining our electric distribution system and include costs of our jointly owned generation and transmission facilities.  The increase of $10.7 million for the third quarter and the increase of $8.8 million in the first nine months were largely due to higher service restoration costs in 2011 vs. major storms in 2010.

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 for 2011 is 50.3 percent compared to 39.9 percent for 2010.  The variance includes the impact of low pre-tax earnings in 2011 combined with a $0.2 million unfavorable prior year true-up recorded in 2011, and the impact of the PPACA, as modified by the Health Care and Education Reconciliation Act, which represented 7 percent of the 2010 effective tax rate.

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 for the third quarter and $0.1 million for the first nine months of 2011 compared to less than $0.1 million for the third quarter and $0.2 million for the first nine months of 2010. Significant variances in line items that comprise other income and other deductions on the Condensed Consolidated Statements of Operations are described below.

Equity in earnings of affiliates:  These are earnings on our equity investments including VELCO, Transco and VYNPC.  The increase of $1.5 million for the third quarter and $4.9 million for the first nine months of 2011 versus 2010 is principally due to the return on the $34.9 million investment that we made in Transco in December 2010.

Other deductions: The increase of $23.9 million in the third quarter and $26.6 in the first nine months of 2011 is primarily related to a $19.5 million termination payment to Fortis Inc., $6.6 million of expenses for outside counsel and investment advisors, related to the merger agreements with Fortis and Gaz Métro, and $0.4 million of lower income for the first nine months of 2011 versus 2010 from variable life insurance policies.

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

Interest on long-term debt:  The increase of $0.7 million in the third quarter and $1.5 million in the first nine months of 2011 is principally due to interest on long-term debt from bond issuances in December 2010 and in June 2011, and 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.

Our power supply management philosophy is to strike a balance between cost and risk.  We strive to minimize power costs while keeping liquidity risks at conservative levels.  Risk mitigation strategies are built around minimizing both forward price risks and operational risks while limiting the potential for both our collateral exposure and inefficient deployment of capital.  Other risks are mitigated by the power and transmission cost recovery process contained in the PCAM (see Retail Rates and Alternative Regulation). We also seek to reduce net power costs and mitigate price risks through limited wholesale transactions primarily to sell excess energy and to occasionally cover anticipated energy shortfalls.  FTR auctions provide us with opportunities to economically hedge our exposure to congestion charges that result from transmission system constraints between generator resources and load areas. FTRs are awarded to successful bidders in periodic auctions that are administered by ISO-NE.

Our current power forecast suggests we have excess energy supply during 2011 and early 2012.  In 2010, we conducted a successful online auction to sell most of our projected excess energy for 2011 in the forward market, on a unit-contingent basis, at fixed prices in order to reduce market price volatility and gain a measure of revenue certainty while remaining strictly within potential collateral exposure limits.

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

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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.

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

There are two sellback contracts with provisions that apply to existing and future VJO power contract purchases.  The first resulted in the sellback of 25 MW of capacity and associated energy through April 30, 2012, which has no net impact currently since an identical 25 MW purchase was made in conjunction with the sellback. We have a 23 MW share of the 25 MW sellback. However, since the sellback ends six months before the corresponding purchase ends, the first sellback will result in a 23 MW increase in our capacity and energy purchases for the period from May 1, 2012 through October 31, 2012.

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 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.

The HQUS PPA will replace approximately 65 percent of the existing VJO power contract discussed above, which along with the VY PPA supply the majority of Vermont’s current power needs. The VJO power contract and the VY PPA expire within the next several years.

The obligations of HQUS and each Buyer are contingent upon the receipt of certain governmental approvals. 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. Technical hearings were held and final legal briefs were filed in the first quarter of 2011.  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 MW allocations as a result of our September 1, 2011 purchase of Vermont Marble.

Other Future Power Agreements:  On July 27, 2011, in cooperation with an energy management firm, we conducted a highly structured Internet auction that involved a dozen pre-screened north-eastern 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 our existing contract with Vermont Yankee.  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 when we had remaining supply gaps next year. The third contract filled our energy needs during the planned Vermont Yankee refueling 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. 

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In September 2011, we used the auction process to sell small amounts of projected excess energy in the first two months of 2012.

Vermont Yankee:Under Vermont law, in addition to a favorable Vermont legislative vote, the PSB must issue a Certificate of Public Good in order for the plant to continue to operate after March 21, 2012.  On February 24, 2010, in a non-binding vote, the Vermont Senate voted against allowing the PSB to consider granting the Vermont Yankee plant another 20-year operating license.  On November 2, 2010 Vermont elected a new governor who continues to strongly advocate for the closure of the Vermont Yankee plant when its current license expires.

After the November election, Entergy announced it had begun pursuing a possible sale of the plant, apparently concluding that the plant had a better chance at remaining part of Vermont’s power supply under new ownership.  We vigorously engaged in contract talks with Entergy-Vermont Yankee for the specific purpose of increasing the chances the plant would continue to operate beyond 2012.  On March 29, 2011, Entergy announced its sale process had concluded unsuccessfully.  Consequently, the potential for state legislative and regulatory approval of continued plant operations is now, in our view, extremely low.  However, as discussed more fully below, Entergy-Vermont Yankee is seeking to operate the plant beyond March 21, 2012 without such approvals.

On March 10, 2011, the NRC voted 4-0 to approve the 20-year license extension through March 21, 2032 requested by Entergy-Vermont Yankee.  This approval removes the last federal-level regulatory requirement for relicensing of the Vermont Yankee station.

Entergy-Vermont Yankee, previously attempting to overcome legislative concerns, challenged the state’s authority as it relates to relicensing.  In a federal lawsuit filed on April 18, 2011, Entergy-Vermont Yankee contended that the state was improperly attempting to interfere with its relicensing.  In the complaint filed in U.S. District Court for the District of Vermont, Entergy-Vermont Yankee is seeking a judgment to prevent the state of Vermont from forcing the Vermont Yankee nuclear power plant to cease operation on March 21, 2012.  The complaint seeks both declaratory and injunctive relief, and contends that Vermont’s attempts to close the plant are preempted by the Atomic Energy Act, theFederal Power Act and the Commerce Clause of the U.S. Constitution.  The state of Vermont has vigorously defended its position.

On June 27, 2011, ISO-NE announced that studies have shown Vermont Yankee is “needed to support the grid’s ability to reliably meet demand in Vermont, southern New Hampshire and portions of Massachusetts, as well as reliability for the entire region’s power system.”

On July 18, 2011, the federal district court denied Entergy-Vermont Yankee’s motion for a preliminary injunction to enjoin the state from enforcing Vermont statutes that would require Vermont Yankee to cease operations after March 21, 2012.  In denying the motion, the court expressly declined to issue a holding regarding Entergy’s likelihood of success on the merits but noted that Entergy raised serious questions regarding its Atomic Energy Act preemption claim, which warrant further briefing and a “full-dress” trial on the merits.   The court also took judicial notice that on June 28, 2011, Standard & Poor’s affirmed Entergy Corporation’s corporate credit and issue ratings but revised its credit outlook from “stable” to “negative.”

On July 25, 2011, Entergy announced that its board of directors approved the refueling scheduled for October 2011, despite uncertainty about whether the Vermont Yankee plant will continue operations after March 21, 2012.  The refueling period ended November 3, 2011.  We purchased replacement power for this expected outage as discussed below in Future Power Agreements.

During the week of September 12, 2011, the U.S. District Court for the District of Vermont held a trial on the merits of Entergy-Vermont Yankee’s complaint.  At the end of September 2011, both parties filed final briefs for the court to consider before making its decision, which is expected in November.

We are evaluating the potential impact of the litigation on our financial statements and on our customers.  The outcome of this matter is uncertain at this time.

TRANSMISSION MATTERS

On September 30, 2011, the Commonwealth of Massachusetts filed a complaint with the FERC pursuant to sections 206 and 306 of the Federal Power Act.  The complaint was filed on behalf of various parties, including the DPS, and named various New England transmission owners and ISO-NE.  The complainants are seeking an order from the FERC to reduce the 11.14 percent base return on equity used in calculating formula rates for transmission service under the ISO-NE open access transmission tariff to a level of 9.2 percent, claiming that the formula rates are unjust and unreasonable.  The complainants further request that the FERC: 1) institute paper hearing procedures to investigate the Base ROE and establish a just and reasonable equity return to be reflected in rates for transmission service provided by the New England transmission owners under the ISO-NE open access transmission tariff; 2) establish the earliest possible refund effective date (i.e., the date of complaint), consistent with FERC policy; and 3) direct ISO-NE to make refunds reflecting the difference between transmission rates reflecting an 11.14 percent Base ROE and rates reflecting a just and reasonable Base ROE.  We are unable to predict the outcome of this matter at this time or the potential impact on our financial statements; however we recover the majority of our share of any higher costs under the quarterly PCAM adjustment, included in our alternative regulation plan.

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RECENT ENERGY POLICY INITIATIVES

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

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.

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 aPublic Review DRAFT 2011 ofthe Comprehensive Energy Plan for review and comment. The plan addresses Vermont’s energy future for electricity, thermal energy, transportation, and land use.

Under the draft plan, which will be 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 has generated significant public comment.  The formal comment period ended November 4, 2011 and a final version of the plan is expected to be released in the near future.

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.

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 Condensed Consolidated Financial Statements. Our critical accounting policies and estimates are described in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2010.  Also, see Note 2 - Summary of Significant Accounting Policies to the accompanying Notes to Condensed Consolidated Financial Statements.

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FASB – IASB Convergence The FASB and IASB are working on joint projects to bring U.S. GAAP closer to IFRS, resulting in a major overhaul and reshaping of U.S. GAAP.  The FASB’s project plan anticipates the completion of some projects in 2011.  We have not yet evaluated the impact, if any, that the adoption of the new standards may have on our consolidated financial statements.

On February 24, 2010, the SEC issued a statement of its position regarding global accounting standards.  Among other things, the SEC stated that it has directed its staff to execute a work plan, which will include consideration of IFRS as it exists today and after the completion of various convergence projects currently under way between U.S. and international accounting standards-setters.  By the end of 2011, the SEC is expected to provide an update on their work plan.  If the SEC determines in 2011 to move forward with IFRS, the first time that U.S. companies would report under such a system would be no earlier than 2015.  Since we are an accelerated filer, we would be required to adopt IFRS in 2016. 

Dodd-Frank Act On July 21, 2010, the Dodd-Frank Act was signed into law. While the Dodd-Frank Act has broad implications to the financial services industry, there are some new mandates for public companies that may require changes in corporate governance, compensation, government regulation of the over-the-counter derivatives market, accounting and other areas.  The SEC has issued proposed rules for certain provisions that are scheduled to be approved by the end of 2011.  We have already implemented changes related to non-binding shareholder advisory votes on executive compensation and compensation and benefit plan risk assessments.

The Dodd-Frank Act requires entities to clear most over-the-counter derivatives through regulated central clearing organizations and to trade the derivatives on regulated exchanges.  In September 2010, we filed for a waiver of the Dodd-Frank Act provision that ends the exemption under Section 2(h) of the Commodity Exchange Act.  If granted, an extension of time will be provided, exempting us while regulatory rulemaking is taking place and while we evaluate whether our derivatives are subject to the regulations in the Commodity Exchange Act or as adjusted in the Dodd-Frank Act.  Even with this exemption, however, we may be subject to reporting requirements pursuant to an interim rule that will pertain to swap arrangements entered into before the Dodd-Frank Act.  We are monitoring and evaluating developments to ensure compliance with any such reporting requirements.

We are uncertain to what degree this legislation may affect our business in the future, but we are evaluating these additional regulatory requirements and the potential impact on our financial statements.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

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 Part II, Note 6, Fair Value and Part II, Note 10, Power-Related Derivatives. Also, see our 2010 Form 10K, Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies and Estimates, and Part II, Item 7A, Quantitative and Qualitative Disclosures About Market Risk.  There have been no material changes to the market price sensitivity information through September 30, 2011.

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 Condensed Consolidated Balance Sheets depending on whether the change in fair value is an unrealized loss or unrealized gain, with an offsetting amount recorded as a decrease or increase in the related derivative asset or liability.  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.

Equity Market Risk As of September 30, 2011, our pension trust held marketable equity securities of $38.8 million, our postretirement medical trust funds held marketable equity securities of $10.5 million, our Millstone Unit #3 decommissioning trust held marketable equity securities of $4.3 million and our Rabbi Trust held variable life insurance policies with underlying marketable equity securities of $2.3 million.  These equity investments experienced mixed performance through September 30, 2011 and positive performance in 2010.  Also see 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.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Management of the company, under the supervision and with participation of our Chief Executive Officer and Principal Financial and Accounting Officer, conducted an evaluation of the effectiveness of the design and operation of the company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)), as of September 30, 2011.  Based on this evaluation, our Chief Executive Officer and Principal Financial and Accounting Officer concluded that, as of September 30, 2011, the company’s disclosure controls and procedures are effective at the reasonable assurance level.

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 September 30, 2011 that have materially affected, or are reasonably likely to materially affect, the company’s internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings.

The company is involved in legal and administrative proceedings in the normal course of business, 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: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.

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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 Gaz Métro merger were misleading and/or incomplete, and that the CVPS Board had violated its fiduciary duties.  The proposed consolidated amended complaint also contains claims for aiding and abetting fiduciary breaches against CVPS and Gaz Métro.  The proposed consolidated amended complaint seeks, 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.

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 proposed Gaz Métro 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 proposed 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. The parties to the Davis action have informed the court of the memorandum of understanding and will be seeking court approval of the proposed settlement. The parties to the MOU reserved their rights with respect to the determination of plaintiffs’ attorneys fees, if any, when our settlement agreement is reviewed by the court.

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, contains 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.

On October 14, 2011, CVPS and the other defendants filed motions to dismiss the federal IBEW complaint.

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, 2010, which could materially affect our business, financial condition or future results.

We have risks associated with the operation of nuclear facilities.  Changes in security and safety requirements could result from events such as a serious nuclear incident outside of our control.  The NRC plans to perform additional operational and safety reviews of nuclear facilities in the U.S. due to the nuclear-related incidents in Japan resulting from the March 2011 earthquake and tsunami.  The lessons learned from the Japan events and NRC reviews may impact future operations and capital requirements at U.S. nuclear facilities.  Although we have no reason to anticipate a serious nuclear incident at the nuclear plants in which we have an ownership interest, if an incident did occur, it could have a material adverse effect on our financial position, results of operations and cash flows.

We have risks associated with the negative effects of the U.S. debt downgrade, which initially had an adverse effect on financial markets.  On August 5, 2011, Standard & Poor’s lowered the long-term sovereign credit rating of U.S. Government debt obligations from AAA to AA+.  On August 8, 2011, S & P also downgraded the long-term credit ratings of U. S. government sponsored enterprises.  We are unable to predict the long-term impact on such markets and the impact on the fair value of our investments in pension and postretirement medical trust funds, our Millstone Unit #3 decommissioning trust fund and our Rabbi Trust variable life insurance policies.

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We have risks associated with our transmission costs and we could be exposed to higher transmission costs from our affiliate, Transco that could be material.   Under the VTA, Transco’s costs are offset by credits under the NOATT for certain high voltage transmission facilities they own and for certain services they provide.  Transco is also reimbursed for the costs of certain facilities they own that benefit specific Vermont utilities.  Net Transco costs are billed to Vermont utilities under the VTA.  A decrease in Transco’s regional network service revenues could increase costs for Vermont utilities.  We recover the majority of our share of any higher costs under the PCAM adjustment, included in our alternative regulation plan.

While regional cost-sharing greatly reduces our costs related to qualifying Vermont transmission facilities, we pay our share of the costs of all new and existing NOATT-qualifying facilities located throughout New England.

Risks Related to the Proposed Merger with Gaz Métro:

We may be unable to satisfy the conditions or obtain the approvals required to complete the merger or such approvals may contain material restrictions or conditions.  The merger is subject to approval by CVPS shareholders and numerous other conditions, including the approval of various government agencies.  Governmental agencies may not approve the merger or such approvals may impose conditions on the completion, or require changes to the terms of the merger, including restrictions on the business, operations or financial performance.  These conditions or changes could also delay or increase the cost of the merger or limit our net income or the financial benefits to Gaz Métro or our customers.

The merger may not be completed, which may have an adverse effect on our share price and future business and financial results.  Failure to complete the merger or an unanticipated delay in doing so could negatively affect our share price, as well as our future business and financial results.  Proposed class actions have been brought against our board of directors on behalf of CVPS common shareholders. See “Item 1. Legal Proceeding”, for discussion of pending litigation related to the merger.

We will be subject to business uncertainties and contractual restrictions while the merger is pending.  The work required to complete the merger may place a burden on management and internal resources as their attention may be focused on the merger instead of day-to-day management activities, including pursuing other opportunities.  While the merger is pending, our business operations are restricted by the Merger Agreement to ordinary course of business activities, which may cause us to forgo otherwise beneficial opportunities.

We may lose management personnel and other key employees and be unable to attract and retain such personnel and employees.  Uncertainties about the effect of the merger on management personnel and employees may impair our ability to attract, retain and motivate key personnel until the merger is completed and for a period of time thereafter, which could affect our financial performance.

If completed, the merger may not achieve its intended results.  We entered into the Merger Agreement with Gaz Métro with the expectation that the merger would result in various operational and financial benefits.  If the merger is completed, our ability to achieve the anticipated benefits will be subject to a number of uncertainties, including whether our businesses can be integrated in an efficient and effective manner.  Failure to achieve these anticipated benefits could adversely affect our business and financial results.

Item 6. Exhibits.

(a) List of Exhibits

10.67 Credit Agreement dated as of October 25, 2011 between Central Vermont Public Service Corporation, as Borrower and KeyBank National Association, as Lender. (incorporate by reference to Exhibit 10.67 to the Company’s Form 8-K filed with the SEC on October 26, 2011.

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.

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

Dated November 8, 2011

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