10-Q

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

FORM 10-Q

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

For the quarterly period ended     March 31, 2005    

or

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

For the transition period from _______ to _______

Commission file number     1-8222   

          Central Vermont Public Service Corporation          
(Exact name of registrant as specified in its charter)

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

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

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

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

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

      Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes    X      No         

      Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. As of April 30, 2005 there were outstanding 12,247,369 shares of Common Stock, $6 Par Value.

Page 1 of 48

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Form 10-Q - 2005

Table of Contents

		Page
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Statements of Income (unaudited) for the three    months ended March 31, 2005 and 2004	3
	Condensed Consolidated Statements of Comprehensive Income (unaudited) for the    three months ended March 31, 2005 and 2004	4
	Condensed Consolidated Balance Sheets as of March 31, 2005 (unaudited) and    December 31, 2004	5
	Condensed Consolidated Statements of Retained Earnings (unaudited) for the    three months ended March 31, 2005 and 2004	7
	Condensed Consolidated Statements of Cash Flows (unaudited) for the    three months ended March 31, 2005 and 2004	8
	Notes to Condensed Consolidated Financial Statements	9
Item 2.	Management's Discussion and Analysis of Financial Condition and    Results of Operations	27
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	44
Item 4.	Controls and Procedures	45
PART II	OTHER INFORMATION	46
SIGNATURES		47
EXHIBIT INDEX		48

Page 2 of 48

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (in thousands, except per share data) (unaudited)
	Three Months Ended March 31         2005                   2004
Operating Revenues	$75,643		$84,114
Operating Expenses   Operation      Purchased Power      Production and Transmission      Other Operation   Maintenance   Depreciation   Other taxes, principally property   Income tax benefit   Total Operating Expenses	41,848  7,193  22,392  3,603  4,065  3,601     (6,149)   76,553		57,922  6,642  11,162  3,624  4,028  3,442     (2,086)   84,734
Operating Loss	(910)		(620)
Other Income and Deductions   Equity in earnings of affiliates   Equity in earnings of non-utility investments   Allowance for equity funds during construction   Other income   Other deductions   Benefit (Provision) for income taxes   Total Other Income and Deductions	483  932  13  1,700  (3,594)            6        (460)		215  1,473  29  2,528  (2,342)      (534)     1,369
Total Operating and Other (Loss) Income	(1,370)		749
Interest Expense   Interest on long-term debt   Other interest   Allowance for borrowed funds during construction Total Interest Expense	1,849  1,412           (4)    3,257		2,488  179         (12)    2,655
Loss from continuing operations Income from discontinued operations, net of tax (including gain on         disposal of $12,386 in 2004) Net (Loss) Income Dividends on preferred stock	(4,627)            -  (4,627)         92		(1,906)   12,256  10,350         258
(Loss) Earnings available for common stock	$(4,719)		$10,092
Per Common Share Data: Basic:   Loss from continuing operations   Earnings from discontinued operations   (Loss) earnings per share Diluted:   Loss from continuing operations   Earnings from discontinued operations   (Loss) earnings per share	$(.39)        -  $(.39) $(.39)        -  $(.39)		$(.18)    1.02  $.84  $(.18)    1.00  $.82
Average shares of common stock outstanding - basic Average shares of common stock outstanding - diluted	12,219,130  12,219,130		12,063,879  12,292,759
The accompanying notes are an integral part of these consolidated financial statements
Page 3 of 48
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (in thousands) (unaudited)
		Three Months Ended March 31      2005                       2004
Net (Loss) Income		$(4,627)		$10,350
Other comprehensive income (loss), net of tax: Foreign currency translation adjustments Unrealized loss on investments:    Unrealized holding losses    Realized losses Net unrealized loss adjustment on securities		10  (69)          166           97		(61) 3             -            3
Comprehensive (loss) income		$(4,520)		$10,292
The accompanying notes are an integral part of these consolidated financial statements

Page 4 of 48

CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands) (unaudited)
	March 31             December 31         2005                           2004
ASSETS
Utility plant, at original cost   Less: accumulated depreciation Net utility plant   Construction work-in-progress   Nuclear fuel, net Total utility plant	$505,943   216,767 289,176 8,170         863  298,209	$502,551   213,719 288,832 9,657         971  299,460
Investments and other assets   Investment in affiliates   Non-utility investments   Non-utility property, less accumulated depreciation   Millstone decommissioning trust fund   Available-for-sale securities   Other Total investment in other assets	16,062 38,765 2,533 4,705 12,923      6,068    81,056	16,070 25,670 2,936 4,721 21,918      6,145    77,460
Current assets   Cash and cash equivalents   Available-for-sale securities   Restricted cash   Notes receivable   Accounts receivable, less allowance for uncollectible accounts       ($2,106 in 2005 and $1,886 in 2004)   Accounts receivable - affiliates, less allowance for uncollectible accounts       ($491 in 2005 and $484 in 2004)   Unbilled revenues   Materials and supplies, at average cost   Prepayments   Other current assets   Assets held for sale Total current assets	22,652 29,483 - -  12,467 21,225 217 14,915 3,235 7,092 1,877         388  113,551	11,722 19,262 2,000 29,182 20,832 909 17,693 3,435 6,326 2,213              -  113,574
Deferred charges and other assets   Regulatory assets   Other deferred charges - regulatory   Other Total deferred charges and other assets	32,611 12,841      5,815    51,267	13,141 36,945      6,183    56,269
TOTAL ASSETS	$544,083	$546,763
The accompanying notes are an integral part of these consolidated financial statements

Page 5 of 48

CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands) (unaudited)
	March 31             December 31         2005                           2004
CAPITALIZATION AND LIABILITIES
Capitalization   Common stock, $6 par value, authorized 19,000,000 shares     (issued 12,231,401 and 12,193,093)   Other paid-in capital   Accumulated other comprehensive loss   Deferred compensation - employee stock ownership plans   Retained earnings Total common stock equity   Preferred and preference stock   Preferred stock with sinking fund requirements   Long-term debt   Capital lease obligations Total capitalization	$73,383  51,729  (23) (26)    90,172  215,235  8,054  5,000  126,750       6,842   361,881	$73,153  51,964  (130) (36) 100,512  225,463  8,054  6,000  126,750      7,094  373,361
Current liabilities   Current portion of preferred stock   Accounts payable   Accounts payable - affiliates   Accrued income taxes   Accrued interest   Dividends declared   Nuclear decommissioning costs   Other current liabilities Total current liabilities	1,000  3,947  10,111  4,309  2,093  2,812  5,115    24,084    53,471	2,000  6,478  10,764  573  323  - -  5,436   20,331   45,905
Deferred credits and other liabilities Deferred income taxes Deferred investment tax credits Nuclear decommissioning costs Asset retirement obligations Accrued pension and benefit obligations Other deferred credits - regulatory Other Total deferred credits and other liabilities	22,422  4,383  16,263  3,426  25,070  19,137    38,030   128,731	32,379  4,478  17,183  3,643  23,508  11,155     35,151   127,497
Commitments and contingencies
TOTAL CAPITALIZATION AND LIABILITIES	$544,083	$546,763
The accompanying notes are an integral part of these consolidated financial statements

Page 6 of 48

CONDENSED CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (in thousands) (unaudited)
	Three Months Ended March 31         2005                       2004
Retained earnings at beginning of period   Net loss from continuing operations   Net income from discontinued operations Retained earnings before dividends	$100,512  (4,627)             -  95,885	$88,282  (1,906)   12,256  98,632
Cash dividend declared   Preferred stock   Common stock Total dividends declared Performance share plan Retained earnings at end of period	92      5,621  5,713              -  $90,172	258     5,550  5,808         780  $93,604
The accompanying notes are an integral part of these consolidated financial statements

Page 7 of 48

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (in thousands) (unaudited)
	Three Months Ended March 31         2005                 2004
Cash flows provided (used) by:
OPERATING ACTIVITIES Net (loss) income Deduct: Income from discontinued operations, net of income taxes     Loss from continuing operations Adjustments to reconcile net income to net cash provided by operating activities:      Equity in earnings of affiliates      Dividends received from affiliates      Equity in earnings from non-utility investments      Distribution of earnings from non-utility investments      Depreciation      Amortization of capital leases      Deferred income taxes and investment tax credits      Net deferral of purchased power and related costs      Non-cash charge related to Rate Order      Reserve for loss on power contract (SFAS No. 5 loss accrual)      Deferred and other non-utility revenue      Unrealized losses on investments      Losses on available-for-sale securities      Amortization of premiums on available-for-sale securities      Changes in assets and liabilities:            Decrease (increase) in accounts receivable and unbilled revenues            Decrease in accounts payable            Increase in accrued income taxes            (Increase) decrease in other current assets            Increase in notes receivable - non-utility affiliates            Increase (decrease) in other current liabilities            Decrease (increase) in other long-term assets            Increase (decrease) in other long-term liabilities and other Net cash provided by operating activities of continuing operations	$(4,627)              -   $(4,627) (483) 553  (932) 1,872  4,065  253  (9,908) (83) 21,772  - -   602  362  573  72  2,979  (2,931) 3,736  (282) (5,881) (1,377) (128)    1,567    11,774	$10,350  (12,256) (1,906) (215) 232  (1,473) 2,784  4,028  275  (5,559) (190) - -  14,351  - -  - -  - -  - -  (279) (1,427) 4,488  254  - -  (2,836) 762      (582) 12,707
INVESTING ACTIVITIES      Construction and plant expenditures      Return of capital      Non-utility investments      Investments in available-for-sale securities      Proceeds from sale of available-for-sale securities      Proceeds from repayment of non-utility note      Other investments Net cash provided by (used for) investing activities of continuing operations	(3,407) 35  (15,760) (64,300) 62,600  22,626            99       1,893	(4,415) 127  (49) (168,445) 156,488  - -            (30)    (16,324)
FINANCING ACTIVITIES      Proceeds from exercise of stock options      Proceeds from dividend reinvestment program      Decrease in restricted cash      Retirement of preferred stock      Retirement of long-term debt      Common and preferred dividends paid      Reduction in capital lease obligations      Other Net cash used for financing activities of continuing operations	- -  419  2,000  (2,000) - -  (2,901) (253)          (3)    (2,738)	393  469  2,000  (2,000) (2,508) (3,030) (275)             -     (4,951)
Effect of exchange rate changes on cash Cash flow provided by discontinued operations Net increase in cash and cash equivalents Cash and cash equivalents at beginning of the period Cash and cash equivalents at end of the period	1            -   10,930    11,722  $22,652	(20)    29,800  21,212     23,772  $44,984
The accompanying notes are an integral part of these consolidated financial statements

Page 8 of 48

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - BUSINESS ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

About Central Vermont Public Service Corporation  Central Vermont Public Service Corporation (the "Company") is a Vermont-based electric utility that transmits, distributes and sells electricity, and invests in renewable and independent power projects. The Company's wholly owned subsidiaries include: Catamount Energy Corporation ("Catamount"), which invests primarily in wind energy projects in the United States and the United Kingdom; Eversant Corporation ("Eversant"), which operates a rental water heater business through its subsidiary, SmartEnergy Water Heating Services, Inc.; Custom Investment Corporation, a passive investment subsidiary; and Connecticut Valley Electric Company Inc. ("Connecticut Valley"), which distributed and sold electricity in parts of New Hampshire. On January 1, 2004, Connecticut Valley completed the sale of substantially all of its plant assets and franchise. See Note 11 - Discontinued Operations.

Basis of Presentation The unaudited interim financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC") including the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain information and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") have been condensed or omitted. The accompanying interim financial statements reflect all adjustments considered necessary for a fair presentation. Operating results for the first quarter of 2005 are not necessarily indicative of the results that may be expected for the 12-months ended December 31, 2005. For further information, refer to the consolidated financial statements and footnotes thereto included in the Company's annual report on Form 10-K for the year ended December 31, 2004 and other SEC filings.

Regulatory Accounting The Company is regulated by the Vermont Public Service Board ("PSB"), the Connecticut Department of Public Utility and Control and the Federal Energy Regulatory Commission ("FERC"), with respect to rates charged for service, accounting, financing and other matters pertaining to regulated operations. The Company prepares its financial statements in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71, Accounting for the Effects of Certain Types of Regulation ("SFAS No. 71"), for its regulated Vermont service territory and FERC-regulated wholesale business. On March 29, 2005, the PSB issued its Order ("Rate Order") on the rate investigation and the Company's request for a rate increase, described in Note 9 - Retail Rates. Although, the Rate Order had a significant unfavorable effect on the Company's financial position and results of operations for the period ended March 31, 2005, the Company's regulated business continues to meet the criteria for accounting under SFAS No. 71. Based on a current evaluation of the factors and conditions expected to impact future cost recovery, management believes future recovery of its regulatory assets in the State of Vermont for its retail and wholesale businesses is probable.

In the event that the Company no longer meets the criteria under SFAS No. 71 and there is not a rate mechanism to recover these costs the accounting impact would be an extraordinary charge to operations of about $26.3 million pre-tax as of March 31, 2005. See Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits for additional information.

Other Current Liabilities The components of other current liabilities are as follows (in thousands):

	March 31, 2005	December 31, 2004
Ratepayer refund - Rate Order*	$6,459	$-
Deferred compensation plans	2,705	2,689
Accrued employee costs - payroll and medical	2,269	4,277
Other taxes and Energy Efficiency Utility	2,288	2,800
Environmental and accident reserves	1,643	1,503
Customer deposits, prepayments and interest	1,469	1,753
Obligation under capital leases	1,020	1,020
Reserve for loss on power contract	1,196	1,196
Accrued joint-owned expenses	333	276
Miscellaneous accruals	4,702	4,817
Total	$24,084	$20,331
* Represents the Company's refund liability required in the Rate Order. See Note 9 - Retail Rates    for additional information.

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Other Deferred Credits and Other Liabilities The components of other deferred credits and other liabilities are as follows (in thousands):

	March 31, 2005	December 31, 2004
Environmental reserve	$4,669	$5,045
Non-legal asset retirement obligation	7,012	6,743
Deferred tax liabilities	4,476	4,530
Reserve for loss on power contract	11,660	11,959
Power contract derivatives	9,953	5,735
Other	260	1,139
Total	$38,030	$35,151

Other Income The pre-tax components of other income are as follows (in thousands):

	Three Months Ended        March 31
	2005	2004
Non-utility revenue	$1,156	$1,052
Interest on non-utility notes receivable	429	613
Interest on temporary investments	340	194
Amortization of contributions in aid of construction	210	205
Non-operating rental income	196	211
Regulatory asset carrying costs	154	210
Other interest and dividends	54	37
Carrying costs - Rate Order*	(822)	-
Miscellaneous other income (loss)	(17)	6
Total	$1,700	$2,528
* Reflects Rate Order adjustments primarily related to amortization of Vermont Yankee sale costs and    Vermont Yankee fuel rod costs for April 1, 2004 through March 31, 2005. See Note 4 - Regulatory    Assets, Deferred Charges and Deferred Credits.

Other Deductions The pre-tax components of other deductions are as follows (in thousands):

	Three Months Ended        March 31
	2005	2004
Non-utility other operating expense	$1,275	$1,271
Realized losses on available-for-sale securities	573	-
Non-utility bad debt expense	422	584
Vermont Yankee fuel rod disallowance - Rate Order*	403	-
Supplemental retirement benefits and insurance	253	196
Other taxes	171	48
Intangible assets amortization	43	90
Asset impairment charges - Catamount	33	-
Miscellaneous other deductions	421	153
Total	$3,594	$2,342
* Reflects disallowance of a portion of deferred costs related to a Vermont Yankee unscheduled outage    in mid-2002. See Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits.

Stock-Based Compensation The Company applies Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees ("APB 25"), and related Interpretations in accounting for its stock option plans and follows the disclosure requirements of SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of SFAS No. 123. The Company did not grant stock options during the three months ended March 31, 2005 and 2004, therefore there is no difference in net income or per share amounts for SFAS No. 123 disclosure purposes.

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Earnings Per Share ("EPS") The Condensed Consolidated Statement of Income includes 'basic' and 'diluted' per share information. Basic EPS is calculated by dividing net income, after preferred dividends, by the weighted-average common shares outstanding for the period. Diluted EPS follows a similar calculation except that the weighted-average common shares is increased by the number of potentially dilutive common shares. Since the Company incurred a loss in the first quarter of 2005, the potentially dilutive common shares are not included in the computation of diluted EPS. Also, unvested restricted stock is only included in the computation of diluted shares as they are contingent upon vesting. The table below provides a reconciliation of (loss) earnings available for common stock and average basic and diluted common shares (in thousands, expect share information):

	Three Months Ended   March 31
	2005	2004
Loss from continuing operations Income from discontinued operations Net (loss) income Preferred stock dividend (Loss) earnings available for common stock	$(4,627)            -  $(4,627)          92  $(4,719)	$(1,906)  12,256  $10,350           258  $10,092
Average shares of common stock outstanding - basic    Dilutive effect of stock options    Dilutive effect of restricted stock    Dilutive effect of performance plan shares Average share of common stock outstanding - diluted	12,219,130  - -  - -                 -  12,219,130	12,063,879  162,851  5,892        60,137  12,292,759

At March 31, 2005 the calculation of diluted EPS excludes 162,891 shares of common stock issuable upon exercise of stock options and 5,892 of unvested restricted shares, because their inclusion in the calculation would be anti-dilutive.

At March 31, 2004, all outstanding stock options were included in the computation of diluted shares because the exercise prices were lower than the average market prices of the common shares in the period.

Assets Held for Sale In the first quarter of 2005, the Company entered into a Purchase and Sale Agreement to sell its property located in Ascutney, Vermont. The sale includes the land and service center building which is no longer being used by the Company. This asset is classified as held for sale on the Condensed Consolidated Balance Sheet in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Regulatory accounting treatment related to the sale of property requires that sale costs and any related loss or gain be offset in accumulated depreciation. The net book value of the property was about $0.4 million at March 31, 2005. The Company expects that any resulting gain or loss on the sale will be a nominal amount.

Investments in Marketable Securities  The Company accounts for investments in marketable equity and debt securities in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities ("SFAS No. 115"). At March 31, 2005, all of the Company's marketable securities were classified as available-for-sale and reported at fair value. Unrealized gains and losses are reported as a component of accumulated other comprehensive income (loss), net of tax, in common stock equity. The carrying cost of debt securities is adjusted for amortization of premiums and accretion of discounts from the date of purchase to maturity.

The Company evaluates the carrying value of its investments on a quarterly basis, or when events and circumstances warrant, determining whether a decline in fair value should be considered other-than-temporary. The carrying value is considered impaired when the anticipated fair value, based on cash flow forecasts is less than the carrying value of each investment. In that event, a realized loss is recognized based on the amount by which the carrying value exceeds the fair value of the investment. The Company applies the method our investment managers use for determining cost basis in computing realized gains and losses on the sale of its available-for-sale securities. These realized gains and losses are included in other income or deductions. See Note 6 - Investment Securities.

Cash, Cash Equivalents and Restricted Cash The Company considers all liquid investments with an original maturity of three months or less when acquired to be cash and cash equivalents. Restricted cash at December 31, 2004 was related to mandatory redeemable preferred stock and included $1.0 million for the mandatory sinking fund payment and $1.0 million for the optional sinking fund payment. These payments to the Preferred Shareholders were effective January 1, 2005.

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Supplemental Cash Flow Information Supplemental Cash Flow information is as follows (in thousands):

	Three Months Ended   March 31
	2005	2004
Cash paid during the year for:
Interest (net of amounts capitalized)	$1,334	$3,336
Income taxes (net of refunds)	$38	$52

Auction rate securities Purchases of auction rate securities and proceeds from sale of auction rate securities are included in available-for-sale securities on the Condensed Consolidated Statements of Cash Flows.

Non-cash Operating, Investing and Financing Activities For additional information regarding non-cash activities, see Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits, Note 9 - Retail Rates and Note 10 - Commitments and Contingencies.

Reclassifications The Company will record reclassifications to the financial statements of prior years when considered necessary or to conform to current-year presentation. The reclassification of auction rate securities from cash and cash equivalents to short-term available-for-sale securities in the December 31, 2004 balance sheet resulted in a decrease of $24.5 million to the ending cash and cash equivalents line items as previously presented in the Condensed Consolidated Statement of Cash Flows for the three-month period ended March 31, 2004. The reclassifications also impacted cash flows used in investing activities and net increase in cash and cash equivalents by $9.9 million for the quarter ended March 31, 2004. There was no impact on net income, cash flow from operations, total assets or covenants as a result of this reclassification.

Recent Accounting Pronouncements

SFAS No. 123R: In December 2004, the Financial Accounting Standards Board ("FASB") issued SFAS No. 123R, Share-Based Payments ("SFAS No. 123R"), which replaces SFAS No. 123 and supersedes, APB 25. SFAS No. 123R requires that compensation cost relating to share-based payment transactions be recognized in the financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. The Company has not elected to early adopt SFAS No. 123R. In April 2005, the SEC approved a rule that delayed the effective date of SFAS No. 123R for public companies. As a result, SFAS No. 123 will be effective for the Company in the first quarter of 2006 and will apply to all of the Company's outstanding unvested share-based payment awards as of January 1, 2006 and all prospective awards.

In March 2005, the SEC issued Staff Accounting Bulletin ("SAB") No. 107 which expressed the views of the SEC regarding the interaction between SFAS No. 123R and certain SEC rules and regulations. SAB No. 107 provides guidance related to valuation of share-based payment arrangements for public companies, including assumptions such as expected volatility and expected term. The Company does not expect that adoption of SFAS No. 123R will have a material impact on its financial position or results of operations. The Company is assessing which of the three transition methods allowed by SFAS No. 123R will be elected.

SFAS No. 151: In December 2004, FASB issued SFAS No. 151, Inventory Costs, ("SFAS No. 151") which clarifies the treatment of abnormal freight, handling, and waste costs associated with inventories. This statement requires that abnormal freight, handling, and waste costs be recognized as current expenses and is effective for fiscal years beginning after June 15, 2005. The Company does not believe that adoption of SFAS No. 151 will have a material impact on its financial position or results of operations.

FIN 47: In March 2005, FASB issued FIN 47, Accounting for Conditional Asset Retirement Obligations, which clarifies that the term 'conditional asset retirement obligation' as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 will be effective for the Company in the fourth quarter of 2005. The Company has not determined the impact, if any, FIN 47 will have on its financial position or results of operations and cash flows.

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NOTE 2 - INVESTMENTS IN AFFILIATES

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

	Three Months Ended     March 31
	2005	2004
Operating revenues Operating income (loss) Net income Company's equity in net income Company's ownership interest	$42,349 $56 $162 $95 58.85%	$49,146  $(174) $143  $84  58.85%

VYNPC's revenues shown in the table above include sales to the Company of $14.7 million in the first quarter of 2005 and $17.1 million for the same period in 2004. These purchases are included in Purchased Power on the Condensed Consolidated Statements of Income. Accounts payable to VYNPC amounted to $4.8 million at March 31, 2005 and $5.8 million at December 31, 2004.

Vermont Electric Power Company, Inc ("VELCO") Summarized financial information follows
(in thousands):

	Three Months Ended   March 31
	2005	2004
Transmission revenues Operating income Net income Company's equity in net income Company's common stock ownership interest	$7,982 $2,091 $730 $365 47.02%	$6,333 $1,428 $310 $121 50.49%

VELCO bills the Company on a monthly basis for transmission and administrative costs associated with power and transmission services; these billings include various credits such as those from ISO-New England under the NEPOOL Open Access Transmission Tariff ("NOATT"). VELCO's monthly billings amounted to $0.8 million in the first quarter of 2005 and $3.0 million for the same period in 2004, and are reflected as production and transmission expenses in the Condensed Consolidated Statements of Income. In the first quarter of 2004, VELCO also billed the Company about $1.7 million for its share of NOATT charges. These charges are now billed directly to the Company from ISO-New England. Accounts payable to VELCO amounted to $5.2 million at March 31, 2005 and $4.8 million at December 31, 2004.

Other Affiliates The Company has equity ownership interests in three nuclear plants, including 2 percent in Maine Yankee Atomic Power Company ("Maine Yankee"), 2 percent in Connecticut Yankee Atomic Power Company ("Connecticut Yankee"), and 3.5 percent in Yankee Atomic Electric Company ("Yankee Atomic"). These plants are permanently shut down and are conducting decommissioning activities. The Company's obligations related to these plants are described in Note 10 - Commitments and Contingencies.

NOTE 3 - NON-UTILITY INVESTMENTS

Catamount: Catamount invests in unregulated energy generation projects primarily in the United States and United Kingdom. As of March 31, 2005, Catamount had interests in six operating independent power projects located in Rumford, Maine; East Ryegate, Vermont; Nolan County, Texas; Thuringen, Germany and Mecklenburg-Vorpommern, Germany.

As of March 31, 2005, Catamount had Notes Receivable of $13.2 million, net of allowances of $0.7 million. Notes Receivable is comprised of a $12.9 million note, net of allowance of $0.4 million, associated with the development of a wind site located in Nolan County, Texas, and a $0.3 million note, which has been fully reserved, related to the sale of a development project in the United States.

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Catamount recorded first quarter 2005 earnings of $0.2 million compared to first quarter 2004 earnings of $0.6 million. Catamount or its wholly owned subsidiaries provide certain management, accounting and other services to certain entities in which Catamount holds an equity interest. The fees are designed to recover actual costs or are agreed upon by other equity investors in these entities. Catamount's revenues (included in Other Income on the Condensed Consolidated Statements of Income) include billings of $0.1 million in the first quarters of 2005 and 2004. At March 31, 2005 and December 31, 2004 Accounts Receivable for these billings amounted to $0.6 million, of which $0.5 million was reserved.

Information regarding certain of Catamount's investments follows.

Sweetwater 2 In February 2005, Catamount paid $15.4 million to acquire an equity interest in Sweetwater Wind 2 LLC, a 91.5-MW wind farm in Nolan County, Texas. Sweetwater Wind 2 LLC commenced commercial operations on February 11, 2005.

Rumford Cogeneration ("Rumford") In the first quarter of 2005, Catamount determined that its equity investment in Rumford was impaired; however the impairment was determined to be temporary. Management's assessment was based on the fact that the electric energy rate, a critical component in determining whether an impairment has occurred, is currently being negotiated between the affected parties. Catamount prepared several scenarios based on varying electric energy prices and other assumptions which resulted in a range of possible outcomes ranging from no impairment to an impairment of $1.7 million. At this time, Management does not believe any one scenario has a higher probability of occurrence than the others and therefore has concluded the impairment is temporary.

DK Burgerwindpark Eckolstadt and DK Windpark Kavelstorf GmbH&Co. KG (collectively "Eurowind") In the first quarter of 2005, Catamount recorded an impairment of less than $0.1 million related to its Eurowind investments. The impairment reflects Management's best estimate of the current market value of these investments based on a non-binding offer from a third party to purchase the projects.

Eversant: As of March 31, 2005, Eversant had a $1.4 million equity investment, representing a 12 percent ownership interest in The Home Service Store Inc. ("HSS"). HSS has established a network of affiliate contractors who perform home maintenance repair and improvements for its members. Eversant accounts for this investment on the cost basis.

NOTE 4 - REGULATORY ASSETS, DEFERRED CHARGES AND DEFERRED CREDITS

Under SFAS No. 71, the Company accounts for certain transactions in accordance with permitted regulatory treatment such that regulators may permit incurred costs, typically treated as expenses by unregulated entities, to be deferred and expensed in future periods when recovered in future revenues. In the Rate Order, the PSB determined the annual revenue requirement for the period April 1, 2004 through March 31, 2005, and established that rates during that period included recovery of certain deferred charges and regulatory liabilities. As a result, in March 2005, the Company adjusted certain deferred charges and credits, and began required amortizations of certain regulatory assets and regulatory liabilities beginning April 1, 2004. Additionally, certain deferred charges were reclassified to regulatory assets to reflect rate recovery.

Net regulatory assets, deferred charges and other deferred credits decreased $12.6 million from December 31, 2004 to March 31, 2005. That decrease is primarily attributed to the Rate Order, which resulted in a $15.3 million decrease in certain regulatory assets, deferred charges and deferred credits. The corresponding offset is a $15.3 million pre-tax charge to earnings in March 2005. See Note 9 - Retail Rates for additional information.

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A summary of net regulatory assets, deferred charges and deferred credits follows (in thousands):

	March 31	December 31
	2005	2004
Net regulatory assets, deferred charges and deferred credits
Regulatory assets *
Conservation and load management ("C&LM") (a)	$73	$408
Nuclear refueling outage costs - Millstone	431	647
Income taxes	3,777	3,987
Maine Yankee nuclear power plant dismantling costs (b)	5,553	5,843
Connecticut Yankee nuclear power plant dismantling costs (b)	12,127	2,108
Yankee Atomic nuclear power plant dismantling costs (b)	4,734	-
Vermont Yankee sale costs (non-tax) (c)	3,970	-
Vermont Yankee fuel rod maintenance deferral (d)	1,847	-
Other regulatory assets	99	148
Subtotal Regulatory assets	32,611	13,141
Other deferred charges - regulatory
Vermont Yankee sale costs (tax)	2,887	2,887
Vermont Yankee sale costs (non-tax) (c)	-	6,381
Vermont Yankee replacement energy deferral (e)	-	834
Connecticut Yankee incremental dismantling costs (b)	-	10,545
Yankee Atomic incremental dismantling costs (b)	-	7,162
Vermont Yankee fuel rod maintenance deferral (d)	-	3,401
Unrealized loss on power contract derivatives (f)	9,954	5,735
Subtotal Other deferred charges - regulatory	12,841	36,945
Other deferred credits - regulatory
Millstone Unit #3 decommissioning (g)	255	629
IPP Settlement Reimbursement and VEPPI cost mitigation (h)	587	1,200
Vermont utility overearnings for 2001 - 2003 (i)	11,528	7,345
Connecticut Valley allocated costs (j)	4,433
Vermont Yankee NEIL Insurance refund (k)	479	-
Asset Retirement Obligation - Millstone Unit #3	1,280	1,078
Unrealized gain on power contract derivatives (f)	-	385
Other (l)	575	518
Subtotal Other deferred credits - regulatory	19,137	11,155
Net regulatory assets, deferred charges and other deferred credits	$26,315	$38,931
* Regulatory assets are being recovered in retail rates and, with the exception of C&LM and Other    regulatory assets, include an associated return.

1. Pursuant to the Rate Order, certain regulatory assets related to C&LM programs were reduced, resulting in a $0.3 million pre-tax charge to earnings in March 2005. Other costs are being amortized over a two-year period beginning April 1, 2004.

Estimated decommissioning costs related to the Company's equity investments in Maine Yankee, Connecticut Yankee and Yankee Atomic. See Note 10 - Commitments and Contingencies for additional information related to nuclear plant decommissioning. These costs are being recovered in retail rates. The Rate Order required the following: 1) previously deferred incremental dismantling costs for the twelve months ended March 31, 2005 be expensed to reflect rate recovery during that time; 2) Yankee Atomic incremental dismantling costs already paid by the Company be amortized over a three-year period ($0.5 million annually) beginning April 1, 2004, and 3) beginning April 1, 2006, for each plant, differences between actual decommissioning cost payments and amounts included for rate recovery, be deferred until the Company's next rate proceeding.

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In March 2005, the Company recorded a $2.4 million pre-tax charge to earnings related to Connecticut Yankee ($0.2 million) and Yankee Atomic ($2.2 million) deferred incremental dismantling costs, to reflect adjustments required in the Rate Order. This included a $1.9 million charge to purchased power expense and a $0.5 million charge to operating expense. Deferred charges were also reclassified to regulatory assets, to reflect rate recovery.

2. Regulatory asset related to deferred incremental Vermont Yankee sale costs (excluding incremental income tax expense) that resulted from the difference between costs that the Company would have incurred had it not pursued the sale and those it incurred by pursuing the sale. Pursuant to the Rate Order, these costs are being amortized over a three-year period ($2.0 million annually) beginning April 1, 2004.

In March 2005, the Company recorded a $2.5 million pre-tax charge to earnings to reflect adjustments required in the Rate Order. This included a $2.0 million charge to operating expense and a $0.5 million reduction of interest income related to adjusted carrying costs. Deferred charges were also reclassified to regulatory assets, to reflect rate recovery.

3. Regulatory asset related to deferred costs associated with defective fuel rods at the Vermont Yankee plant that caused an unscheduled outage in mid-2002. Pursuant to the Rate Order, these deferred costs were reduced by $0.4 million. The remaining regulatory asset is being amortized over a three-year period ($0.9 million annually) beginning April 1, 2004.

In March 2005, the Company recorded a $1.6 million pre-tax charge to earnings to reflect adjustments required in the Rate Order. This included a $0.9 million charge to operating expense, a $0.4 million charge to other deductions, and a $0.3 million decrease in interest income. Deferred charges were also reclassified to regulatory assets, to reflect rate recovery.

4. Deferred charges related to incremental replacement power costs incurred as a result of an unscheduled outage at the Vermont Yankee plant in 2004. These deferred charges were reduced to zero pursuant to the Rate Order, to reflect rate recovery. In March 2005, this resulted in a $0.8 million pre-tax charge to purchased power expense.
5. The Company records derivative contracts on the Condensed Consolidated Balance Sheets at fair value. Based on a PSB-approved Accounting Order, changes in fair value of these derivatives are recorded as deferred charges or deferred credits on the Condensed Consolidated Balance Sheets depending on whether the fair value is an unrealized loss or gain, with an offsetting amount recorded as a decrease or increase in the related derivative asset or liability.
6. Regulatory liabilities related to Millstone Unit #3 decommissioning costs that were being recovered in rates but the Company's share of decommissioning payments were suspended. The regulatory liability was reduced pursuant to the Rate Order. This resulted in a $0.4 million pre-tax decrease in operating expense in March 2005. These costs are being returned to ratepayers in rates over a three-year period beginning April 1, 2004.
7. Regulatory liabilities related to IPP settlement and VEPPI cost mitigation were reduced pursuant to the Rate Order. The Company recorded a $0.5 million pre-tax reduction in expense related to adjustments required in the Rate Order. This included a $0.3 million reduction in purchased power expense, a $0.1 million reduction in operating expense and a $0.1 million reduction in interest expense. These costs are being returned to ratepayers in rates over a three-year period beginning April 1, 2004.
8. Regulatory liabilities related to utility overearnings for the periods 2001 - 2003 due to the Rate Order, which required that these amounts be recalculated using a cost of service based methodology. The Rate Order required that the Company amortize the total regulatory liability over a four-year period ($3.8 million annually) beginning April 1, 2004. In March 2005, adjustments required in the Rate Order resulted in a net $4.1 million pre-tax charge to earnings.

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Required adjustments to the regulatory liability included: 1) a $12.1 million increase resulting from recalculation of overearnings for the periods 2001 - 2003; 2) a $3.8 million decrease resulting from amortization for April 1, 2004 through March 31, 2005; 3) a $0.3 million decrease related to adjusted carrying costs; and 4) a $3.8 million decrease resulting from reversal of the regulatory liability associated with 2004 utility overearnings. See Note 9 - Retail Rates for additional information.

9. Pursuant to the Rate Order, the Company was required to apply the 2004 gain on the Connecticut Valley asset sale to the benefit of ratepayers through amortizations over a three-year period ($2.2 million annually) beginning April 1, 2004. In March 2005, the Company established a regulatory liability in the amount of $6.6 million pre-tax, per the Rate Order, offset by amortization of $2.2 million. This resulted in a net $4.4 million pre-tax charge to earnings in March 2005. See Note 9 - Retail Rates for additional information.
10. Pursuant to PSB approval of the Vermont Yankee sale, distributions from Nuclear Electric Insurance Limited ("NEIL") received by Vermont Yankee and passed to the Company must benefit ratepayers through programs to promote renewable resources.
11. The Rate Order required adjustments to other regulatory liabilities that resulted in a $0.1 million pre-tax charge to earnings. This reflected a requirement that tree trimming and pole treating expenditures below those amounts included in retail rates be deferred as regulatory liabilities and any amounts in excess be recorded as deferred charges. These amounts would then carry forward for use in future years.

NOTE 5 - LONG-TERM DEBT
Utility Substantially all of the Company's utility property and plant is subject to liens under the First Mortgage Bonds. No sinking fund payments are due on long-term debt for 2005 through 2007. Currently, the Company is not in default under any of its debt financing documents.

The Company's long-term debt indentures, letters of credit and Articles of Association contain financial and non-financial covenants. At March 31, 2005, the Company was in compliance with all covenants.

NOTE 6 - INVESTMENT SECURITIES

Available-for-sale securities  At March 31, 2005, Current Assets associated with available-for-sale securities increased by $10.2 million and Investments and Other Assets (long-term) decreased by $9.0 million reflecting the Company's intent to liquidate certain available-for-sale securities within one year.

The Company evaluates the carrying value of these investments on a quarterly basis, or when events and circumstances warrant, to determine whether a decline in fair value is considered temporary or other-than-temporary. The Company considers several criteria in evaluating other-than-temporary declines, including 1) length of time and extent to which market value has been less than cost; 2) financial condition and near-term prospects of the issuer; and 3) intent and ability of the Company to retain its investment in the issuer for a period of time sufficient to allow for any anticipated recovery in market value. In the first quarter of 2005, the Company recorded a $0.3 million impairment of certain available-for-sale investments based on its intent to liquidate those securities prior to their original maturity dates. Based upon forecasted cash flow needs, those securities closest to maturity were impaired. Generally, a security close to its maturity date should have less pricing volatility due to interest rate movements than one further from its maturity date.

In the first quarter of 2005, the Company also recorded $0.1 million of realized losses and $0.3 million of debt security premiums amortization to interest income as a deduction from the coupon interest earned on available-for-sale securities.

The unrealized losses on available-for-sale securities shown below, both on an individual and aggregate basis, are minor when compared to the original costs, and are related to securities the Company expects to hold to maturity based on forecasted cash needs. Therefore, such unrealized losses are considered temporary.

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Information regarding available-for-sale securities as of March 31, 2005 follows (in thousands):

	March 31, 2005				December 31, 2004
Security Types	Amortized Cost	Fair Value	Unrealized Losses	Unrealized Gains	Amortized Cost	Fair Value	Unrealized Losses	Unrealized Gains
Current Assets:
US Government Obligations	-	-	-	-	$2,006	$2,002	$4	-
US Government Agencies	$11,844	$11,844	-	-	8,060	8,010	50	-
Corporate Bonds	5,123	5,114	9	-	4,442	4,425	17	-
Auction Rate Securities	12,525	12,525	-	-	4,825	4,825	-	-
Subtotal	29,492	29,483	9	-	19,333	19,262	71	-
Investments and Other Assets:
US Government Obligations	-	-	-	-	-	-	-	-
US Government Agencies	9,439	9,358	81	-	15,492	15,336	156	-
Corporate Bonds	3,606	3,565	41	-	6,657	6,582	75	-
Subtotal	13,045	12,923	122	-	22,149	21,918	231	-
Total	$42,537	$42,406	$131	-	$41,482	$41,180	$302	-

The following table presents the fair value and gross unrealized losses of the Company's available-for-sale securities, aggregated by investment category and the length of time the securities have been in a continuous loss position, at March 31, 2005 (in thousands):

	Equity Securities		Debt Securities
	Fair Value	Unrealized Losses	Fair Value	Unrealized Losses
Less than 12 months	-	-	$1,473	$25
12 months or more	-	-	6,980	106
Total	-	-	$8,453	$131

Information related to the fair value of debt securities at March 31, 2005 follows (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	$14,012	$15,869	-	$4,800	$34,681

Millstone Decommissioning Trust Fund The Company has decommissioning trust fund investments related to its 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 is required to 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, respectively. For that reason, the fair value is adjusted by realized and unrealized gains and losses, with a corresponding decommissioning liability recorded as Asset Retirement Obligations on the Condensed Consolidated Balance Sheets. Additionally, any appreciation on the trust fund investments is used to offset the related decommissioning liability.

These investments are subject to the requirements of SFAS No. 115, and are recorded at fair value in Investments and Other Assets on the Condensed Consolidated Balance Sheets. The unrealized losses on the decommissioning trust fund are minor when compared to their original cost; therefore, they are considered temporary. At March 31, 2005, losses on equity securities have been in a continuous loss position for less than 12 months. The fair value of these investments is summarized below (in thousands):

	March 31, 2005				December 31, 2004
Security Types	Amortized Cost	Fair Value	Unrealized Gains	Unrealized Losses	Amortized Cost	Fair Value	Unrealized Gains	Unrealized Losses
Equity Securities	$2,544	$3,721	$1,004	$27	$2,464	$3,537	$1,093	$20
Debt Securities	1,148	1,170	29	7	1,103	1,144	43	2
Cash and other	14	14	-	-	40	40	-	-
Total	$3,706	$4,705	$1,033	$34	$3,607	$4,721	$1,136	$22

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The following table presents the fair value and gross unrealized losses of these investments, aggregated by investment category and the length of time the securities have been in a continuous loss position, at March 31, 2005 (in thousands):

	Equity Securities		Debt Securities
	Fair Value	Unrealized Losses	Fair Value	Unrealized Losses
Less than 12 months	$236	$27	$-	$0
12 months or more	-	-	450	7
Total	$236	$27	$450	$7

Information related to the fair value of debt securities at March 31, 2005 follows (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	$33	$337	$292	$508	$1,170

NOTE 7 - PENSION AND POSTRETIREMENT BENEFITS

Pension costs and cash funding requirements are expected to increase in future years. At March 31, 2005, the fair value of Pension Plan trust assets was $62.8 million. At December 31, 2004, the fair value of Pension Plan trust assets was $64.2 million.

Net Periodic Benefit Costs
Components of net periodic benefit costs were as follows (in thousands):

	Pension Benefits		Postretirement Benefits
	2005	2004	2005	2004
Net benefit costs include the following components
Service cost	$807	$755	$128	$135
Interest cost	1,464	1,388	361	389
Expected return on plan assets	(1,317)	(1,406)	(119)	(108)
Amortization of prior service cost	100	99	-	-
Recognized net actuarial loss	49	-	278	345
Amortization of transition (asset) obligation	-	(37)	64	64
Net periodic benefit cost	1,103	799	712	825
Less amounts capitalized	167	124	108	128
Net benefit costs expensed	$936	$675	$604	$697

The Medicare Part D subsidy is about $0.1 million in the first quarter of 2005 and is expected to be about $0.3 million for the year 2005.

NOTE 8 - INCOME TAXES

Rate Order: In March 2005, the Company recorded a $21.8 million pre-tax, or $11.2 million after-tax, charge to utility earnings due to the Rate Order. The related $10.0 million income tax benefit included in taxes on income also includes a $1.6 million favorable impact resulting from a higher projected 2005 income tax rate. The remaining $0.6 million benefit is included in Benefit (provision) for income taxes.

Discontinued Operations: In the first quarter of 2004, taxes on income included a $5.9 million benefit related to the loss accrual resulting from the termination of the power contract with Connecticut Valley as described in Note 11 - DiscontinuedOperations.

NOTE 9 - RETAIL RATES

The Company recognizes adequate and timely rate relief is required to maintain its financial strength, particularly since Vermont law does not allow power and fuel costs to be passed to consumers through fuel adjustment clauses. The Company will continue to review costs and request rate increases when warranted.

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On April 7, 2004, the PSB issued an order to investigate the Company's retail rates. On July 15, 2004, the Company filed a cost of service study pursuant to the rate investigation, and filed a request for a 5.01 percent rate increase, effective April 1, 2005. The Company also requested that the two cases be consolidated; that request was later approved by the PSB. In October 2004, both the DPS and AARP, interveners in the case, filed testimony with the PSB. Technical hearings with the PSB began in early November 2004, and hearings and filings continued through February 2005.

In filings with the PSB on February 11 and 16, 2005, the DPS requested: 1) a rate refund or credit to ratepayers retroactive to April 1, 2004 of about 6 percent or $16 million; 2) a rate reduction of about 7 percent or $19 million effective with service rendered April 1, 2005; and 3) an 8.75 percent rate of return on common equity. While supporting the DPS position, AARP proposed the following modifications: 1) a 10 percent rate of return on common equity; 2) amortize deferred debits over a six-year period (the DPS recommended a three-year period); and 3) exclude costs associated with, or resulting from, the Connecticut Valley asset sale from the Company's cost of service.

On February 18, 2005, the PSB approved the Company's request for an Accounting Order that allowed for deferral of 2004 utility earnings in excess of an 11 percent return on equity. Per the Accounting Order, the Company reduced 2004 utility earnings by about $2.3 million after-tax to achieve the 11 percent, and recorded an offsetting pre-tax regulatory liability of $3.8 million to be used or accounted for as the PSB shall determine in its final order.

The last PSB hearing was held on February 18 and the parties filed reply briefs on February 28, 2005. The Company believed its reply brief supported that 1) a rate reduction for the period April 1, 2004 through March 31, 2005 would not be just or reasonable, and 2) a 2.9 percent rate increase beginning April 1, 2005 was justified. The reduction in the requested rate increase from 5.01 percent to 2.9 percent was based on terms of the power cost settlement reached with the DPS and application of deferred 2004 earnings to reduce deferred charges eligible for rate recovery. Both of these items required approval by the PSB.

On March 29, 2005, the PSB issued its Order ("Rate Order") on the rate investigation and the Company's request for a rate increase. The PSB concluded that the Company's rates were higher than is just and reasonable, and must be reduced. In its Order, the PSB determined the annual revenue requirement beginning April 1, 2004, established rates retroactive to April 7, 2004 and established new rates beginning April 1, 2005. The Rate Order included, among other things, the following: 1) a 1.88 percent rate reduction beginning April 1, 2005; 2) a $3.3 million dollar refund to customers, 3) a 10 percent return on equity (reduced from 11 percent); and 4) a requirement that the gain resulting from the 2004 sale of Connecticut Valley's assets be applied to the benefit of ratepayers to compensate for increased costs. The Company was also required to file a compliance filing by April 1, 2005 and file a new rate design within 90 days of the Rate Order.

The PSB finalized the rate refund and rate reduction amounts in its April 4, 2005 Compliance Order. The rate refund amounts to about $6.5 million pre-tax and the rate reduction amounts to 2.75 percent ($7.2 million pre-tax on an annual basis).

For accounting purposes, the Rate Order resulted in a $21.8 million, or $11.2 million after-tax, unfavorable effect on utility earnings in March 2005. The primary components of the charge to earnings include: 1) a revised calculation of overearnings for the period 2001 - 2003; 2) application of the gain resulting from the Connecticut Valley sale to reduce costs; 3) a customer refund for over-collections for the period April 7, 2004 through March 31, 2005; and 4) amortization of costs and other adjustments required in the Rate Order. These are described in more detail below (all on a pre-tax basis).

1. Per the Company's July 2001 PSB-approved rate settlement, utility earnings were capped at 11 percent for the periods 2001 - 2003. The Company used a common-equity-based calculation methodology to calculate utility earnings for those periods, which resulted in overearnings of $0 in 2001, $0.7 million in 2002 and $2.5 million in 2003. In 2002 and 2003, the Company reduced utility earnings to achieve the 11 percent cap and recorded offsetting regulatory liabilities to be addressed in its next rate proceeding. In the Rate Order, the PSB determined that while the Company's calculation methodology was not incorrect and was reasonable given the language in the 2001 rate settlement, a cost-of-service based calculation methodology was more consistent with traditional ratemaking practice. Therefore, the PSB required that the Company recalculate utility earnings for 2001 - 2003 using a cost-of-service-based methodology.

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Based on the recalculation, utility earnings above the 11 percent cap amounted to $2.9 million in 2001, $5.7 million in 2002 and $5.3 million in 2003. The difference in methodologies resulted in overearnings of $10.8 million plus $1.3 million in additional carrying costs for the period 2001 -2003. The Rate Order requires the Company to amortize the resulting $15.3 million regulatory liability, which includes amounts previously deferred, over a four-year period ($3.8 million annually) beginning April 1, 2004.

In March 2005, the Company recorded a $10.8 million charge to operating expense and $1.3 million to other interest expense, offset by a $12.1 million regulatory liability, to reflect the amount to be amortized. The Company also recorded amortizations for the twelve-months ending March 31, 2005, which reduced operating expense and the regulatory liability by $3.8 million. In total, this amounted to a net $8.3 million charge to earnings.

2. Per the Rate Order, the Company was required to apply the 2004 gain on the Connecticut Valley asset sale to the benefit of ratepayers through amortizations over a three-year period beginning April 1, 2004. The PSB determined that ratepayers should be compensated for additional costs resulting from the sale, because it included recovery of these costs in the annual revenue requirement beginning April 1, 2004 and the new rates beginning April 1, 2005. The additional costs represent common infrastructure costs that were previously allocated or charged to Connecticut Valley through a service contract.

The PSB's calculation amounts to $6.6 million, which is the difference between the $21 million the Company received for termination of the long-term power contract with Connecticut Valley and a $14.4 million loss accrual. The loss accrual represented Management's best estimate of the difference between expected future sales revenue, in the wholesale market, for the purchased power that was formerly sold to Connecticut Valley and the cost of purchased power obligations. The Company recorded these items in the first quarter of 2004.

In March 2005, the Company recorded a $6.6 million charge to operating expense, offset by a regulatory liability, to reflect the amount to be amortized. The Company also recorded amortizations for the twelve-months ending March 31, 2005, which reduced operating expense and the regulatory liability by $2.2 million. In total, this amounted to a net $4.4 million charge to earnings.

3. The Rate Order, with revisions from the PSB's Compliance Order, requires a customer refund amounting to about $6.2 million ($3.3 million after-tax) and carrying costs of $0.3 million based on a lump-sum refund. The refund represents over-collections from customers for April 7, 2004 though March 31, 2005 ($1.7 million is attributed to 2005 and $4.5 million is attributed to 2004). On April 25, 2005, the PSB approved a proposal for a lump-sum refund to customers in June 2005 billings. Additionally, on April 25, 2005, the PSB approved application of the $3.8 million regulatory liability for 2004 overearnings (see discussion of February 18, 2005 Accounting Order above) to the refund liability.

In March 2005, the Company reduced revenue by $6.2 million and recorded $0.3 million of other interest expense, offset by a $6.5 million current liability, to reflect the refund due to customers. The Company also reversed the $3.8 million regulatory liability, which reduced operating expense by that amount. In total, this amounted to a net $2.7 million charge to earnings.

4. Other adjustments required in the Rate Order resulted in a $6.4 million unfavorable effect on utility earnings. These adjustments were primarily related to adjusting and amortizing certain deferred charges and credits beginning April 1, 2004, because the PSB included recovery of these costs in determining the annual revenue requirement for April 1, 2004 through March 31, 2005. Amortizations result in the matching of expenses to the period in which the amounts are recovered in rates.

The primary components of the net $6.4 million charge to earnings in March 2005 are as follows:

• a $2.4 million increase in purchased power expense mostly related to expensing of Yankee Atomic incremental dismantling costs and Vermont Yankee 2004 replacement energy costs to reflect rate recovery beginning April 1, 2004;
• a $3.2 million increase in operating expenses mostly related to amortization of Vermont Yankee (non-tax) sale-related costs, Vermont Yankee 2002 fuel rod costs and Yankee Atomic dismantling costs to reflect rate recovery beginning April 1, 2004;
• a $0.8 million decrease in interest income to adjust carrying costs related to Vermont Yankee (non-tax) sale-related costs and Vermont Yankee 2002 fuel rod costs due to rate recovery beginning April 1, 2004;

Page 21 of 48

• a $0.4 million increase in other deductions for disallowance of a portion of Vermont Yankee 2002 fuel rod costs; offset by
• a $0.4 million decrease in other interest expense related to various other adjustments per the Rate Order.

The Rate Order impact on the Condensed Consolidated Statement of Income is shown in the table below. See Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits for the impact on the Condensed Consolidated Balance Sheet.

On April 4, 2005, Standard and Poor's Ratings Services placed the Company's 'BBB-' corporate credit rating on CreditWatch with negative implications.

On April 12, 2005, the Company filed with the PSB a Request for Reconsideration of the Rate Order. Specific items for reconsideration included: 1) treatment of the costs and benefits associated with the January 1, 2004 Connecticut Valley sale; 2) the 10 percent return on equity; and 3) various other matters for clarification.

On April 12, 2005, the DPS filed with the PSB a Motion for Reconsideration of the Rate Order. Specific items for reconsideration included: 1) treatment of costs formerly recovered by the Company through our service contract with Connecticut Valley; and 2) certain adjustments related to the calculation of overearnings for 2001 - 2003.

The Company, DPS and AARP submitted their responses to these motions by April 26, 2005 as required by the PSB. The Company is not able to predict the outcome of these matters at this time.

Income Statement Impacts of the Rate Order:

The table below reflects the unfavorable impacts of the Rate Order on specific line items of the Condensed Consolidated Statement of Income for the first quarter of 2005 on a pre-tax basis (in millions).

Income Statement Line Item
Operating Revenue (#3 above)	$(6.2)
Purchased Power (#4 above)	(2.5)
Other Operation (#1, 2, 3 and 4 above)	(10.7)
Other Income (#4 above)	(0.8)
Other Deductions (#4 above)	(0.4)
Other Interest (#1, 3 and 4 above)	(1.2)
Total Rate Order Impact	$(21.8)

NOTE 10 - COMMITMENTS AND CONTINGENCIES  

Nuclear Investments Nuclear Generating Companies The Company is one of several sponsor companies with ownership interests in Maine Yankee, Connecticut Yankee and Yankee Atomic, and is responsible for paying its ownership percentage of decommissioning and all other costs for each plant. All three of these nuclear plants have been shut down and are undergoing decommissioning. The Company also has a joint-ownership interest in Millstone Unit #3. Its obligations related to these plants are described below.

Maine Yankee, Connecticut Yankee and Yankee Atomic All three companies collect decommissioning and closure costs through wholesale FERC-approved rates charged under power agreements with several New England utilities, including the Company. Historically, the Company's share of these costs has been recovered from its retail customers through PSB-approved rates. Based on the regulatory process, management believes its share of decommissioning and closure costs for each plant will continue to be recovered through the regulatory process. Although, Management believes that these costs will ultimately be recovered from its customers, there is a risk that FERC may not allow full recovery of Connecticut Yankee's increased costs in wholesale rates, as described below. If FERC does not allow these costs to be recovered in wholesale rates, the Company anticipates that the PSB would disallow these costs for recovery in retail rates as well.

The Company's share of Maine Yankee, Connecticut Yankee and Yankee Atomic estimated costs are reflected on the Condensed Consolidated Balance Sheet as regulatory assets and nuclear decommissioning liabilities (current and non-current). These amounts are adjusted when revised estimates are provided by the companies. At March 31, 2005, the Company had regulatory assets of about $5.6 million related to Maine Yankee, $12.1 million related to Connecticut Yankee and $4.7 million related to Yankee Atomic. These estimated costs are being collected from the

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Company's customers through existing retail rate tariffs. See Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits, regarding the impacts of the Rate Order.

Maine Yankee, Connecticut Yankee and Yankee Atomic are seeking recovery of fuel storage-related costs stemming from the default of the United States Department of Energy ("DOE") under the 1983 fuel disposal contracts that were mandated by the United States Congress under the High Level Waste Act. All three are parties to a lawsuit against the DOE seeking damages based on the DOE's default. The trial on determination of damages began on July 12 and ended August 31, 2004. Closing arguments were held in January 2005 and final post-trial briefs were filed in February 2005. The Department of Justice submitted a motion to the court during the damage trial arguing that the spent fuel obligations prior to April 1983 should be treated as an offset to any award of damages. The Court's ruling on that matter is expected to be issued with its overall ruling in the case, which is expected by the end of 2005. None of the plants has included any allowance for potential recovery of these claims in their FERC-filed c ost estimates.

Maine Yankee: The Company has a 2 percent ownership interest in Maine Yankee. Beginning November 1, 2004, Maine Yankee's billings to sponsor companies have been based on its September 16, 2004, FERC approved settlement, which provides for recovery of Maine Yankee's forecasted costs of providing service through a formula rate contained in its power contracts through October 31, 2008 and replenishment of the DOE Spent Fuel Obligation through collections from November 2008 through October 2010.

Connecticut Yankee: The Company has a 2 percent ownership interest in Connecticut Yankee. Costs currently billed by Connecticut Yankee are based on its most recent FERC-filed rates effective February 1, 2005, for collection through 2010. Prior to February 1, 2005, costs were based on FERC-approved rates that became effective September 1, 2000, for collection through 2007.

Connecticut Yankee is currently involved in litigation related to a contract dispute. Also in 2004, Connecticut Yankee filed a rate application with FERC. These matters are discussed in more detail below.

Bechtel Litigation:  Connecticut Yankee is involved in a contract dispute with Bechtel Power Corporation ("Bechtel"), which resulted in termination of the decommissioning services contract between Connecticut Yankee and Bechtel. Connecticut Yankee continues to prosecute its counterclaims and other damages against Bechtel in Connecticut Superior Court. Discovery is underway and a trial has been scheduled for May 2006.

FERC Rate Case Filing:   On July 1, 2004, Connecticut Yankee filed its December 2003 cost estimate with FERC as part of its rate application ("Filing") seeking additional funding to complete the decommissioning project and for storage of spent fuel through 2023. The proposed annual decommissioning collection represented a significant increase in annual charges to the sponsor companies, including the Company, as compared to prior FERC rates. The Connecticut Department of Public Utility Control ("CT DPUC") has intervened in this rate case alleging Connecticut Yankee imprudence in its decommissioning effort. Bechtel has also intervened.

On August 30, 2004, FERC issued an order: 1) accepting for filing the new charges proposed by Connecticut Yankee in its rate application; 2) suspending these revised charges until February 1, 2005; 3) establishing Administrative Law Judge hearing procedures and schedules; 4) denying the CT DPUC and Connecticut Office of Consumer Counsel ("OCC") request for an accelerated hearing schedule and for a bond or other security for potential refunds; 5) denying the declaratory ruling sought by the CT DPUC and OCC; and 6) granting Bechtel's motion to intervene as well as allowing interventions by other applying parties. On September 7, 2004, a FERC administrative law judge was appointed to the case. The current schedule provides for the hearings to start June 1, 2005. Connecticut Yankee anticipates that the process of resolving the matters in the Filing is likely to be contentious and lengthy.

The Company continues to believe that FERC will approve recovery of Connecticut Yankee's increased costs in wholesale rates based on the nature of costs and previous rulings at other nuclear companies. Once approved by FERC, the Company believes it is unlikely that the PSB would not allow these FERC-approved costs to be recovered in retail rates. The timing, amount and outcome of the Bechtel litigation and FERC rate case filing cannot be predicted at this time.

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Yankee Atomic: The Company has a 3.5 percent ownership interest in Yankee Atomic. Costs billed by Yankee Atomic are based on an April 4, 2003 FERC filing, in which FERC approved the resumption of billings starting June 2003 for a recovery period through 2010.

Millstone Unit #3 The Company has a 1.7303 percent joint-ownership interest in Millstone Unit #3, in which Dominion Nuclear Corporation ("DNC") is the lead owner with about 93.47 percent of the plant joint-ownership. The Company has an external trust dedicated to funding its joint-ownership share of future decommissioning costs.

In January 2004, DNC filed, on behalf of itself and the two minority owners, including the Company, a lawsuit against the DOE seeking recovery of costs related to storage of spent nuclear fuel arising from the failure of the DOE to comply with its obligations to commence accepting such fuel in 1998. The schedule for further proceedings in the lawsuit is not known at this time. Millstone Unit #3 spent fuel from the beginning of commercial operations in 1986 resides in the spent fuel pool, and there is believed to be adequate spent fuel pool storage capability to support expected operations through the end of its current licensed life in 2025. The Company continues to pay its share of the DOE Spent Fuel assessment expenses levied on actual generation and will share in recovery from the lawsuit, if any, in proportion to its ownership interest.

Environmental   Over the years, more than 100 companies have merged into or been acquired by the Company. At least two of the companies used coal to produce gas for retail sale. This practice ended more than 50 years ago. Gas manufacturers, their predecessors and the Company used waste disposal methods that were legal and acceptable then, but may not meet modern environmental standards and could represent a liability.

Some operations and activities are inspected and supervised by federal and state authorities, including the Environmental Protection Agency. The Company believes that it is in compliance with all laws and regulations and has implemented procedures and controls to assess and assure compliance. Corrective action is taken when necessary. Below is a brief discussion of known material issues.

Cleveland Avenue Property The Cleveland Avenue property in Rutland, Vermont, was used by a predecessor to make gas from coal. Later, the Company sited various operations there. Due to coal tar deposits, Polychlorinated Biphenyl contamination and potential off-site migration, the Company conducted studies in the late 1980s and early 1990s to quantify the situation. Investigation has continued, and the Company is working with the State of Vermont to develop a mutually acceptable solution.

Brattleboro Manufactured Gas Facility In the 1940s, the Company owned and operated a manufactured gas facility in Brattleboro, Vermont. The Company ordered a site assessment in 1999 on request of the State of New Hampshire. In 2001, New Hampshire said no further action was required, though it reserved the right to require further investigation or remedial measures. In 2002, the Vermont Agency of Natural Resources notified the Company that its corrective action plan for the site was approved. That plan is now in place.

Dover, New Hampshire, Manufactured Gas Facility In 1999, PSNH contacted the Company about this site. PSNH alleged that the Company was partially liable for cleanup, since the site was previously operated by Twin State Gas and Electric, which merged into the Company the same day that PSNH bought the facility. In 2002, the Company reached a settlement with PSNH in which certain liabilities it might have had were assigned to PSNH in return for a cash payment.

As of March 31, 2005, a $6.0 million reserve for environmental matters is recorded on the Condensed Consolidated Balance Sheet. At December 31, 2004, the reserve was $6.1 million. The reserve represents Management's best estimate of the cost to remedy issues at these sites.  There is no pending or threatened litigation regarding other sites with the potential to cause material expense. No government agency has sought funds from the Company for any other study or remediation.

Catamount In November 2004, Catamount entered into an agreement with a third-party developer for the purchase of wind turbines for a joint development project. Pursuant to the agreement, Catamount made a total of $5.9 million of payments to the turbine supplier in 2004 and a $5.9 million payment in March 2005. The turbine supply agreement calls for a payment of $14.8 million in September 2005, with the remaining contract amount of $32.5 million due based on milestones established in the agreement. When the Sweetwater 3 construction financing is complete in early May 2005, the September 2005 and remaining contract amount will be assumed by the Sweetwater 3 project, pursuant to the construction financing agreement.

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NOTE 11 - DISCONTINUED OPERATIONS

On January 1, 2004, Connecticut Valley completed the sale of substantially all of its plant assets and its franchise to Public Service Company of New Hampshire ("PSNH"). The sale, including termination of the power contract between the Company and Connecticut Valley, resolved all Connecticut Valley restructuring litigation in New Hampshire and the Company's stranded cost litigation at FERC.

For accounting purposes, components of the sale transaction are recorded in both continuing and discontinued operations in the 2004 Condensed Consolidated Statement of Income. First quarter 2004, income from discontinued operations included a gain on disposal of about $21 million pre-tax, or $12.3 million after-tax. In addition to the gain on disposal, the Company recorded a loss on power costs of $8.4 million pre-tax relating to termination of the power contract with Connecticut Valley. The loss is included in Purchased Power in the 2004 Condensed Consolidated Statement of Income. When the two accounting transactions are combined to assess the total impact of the sale, the result is a gain of $3.9 million recorded in the first quarter of 2004.

There are no remaining significant business activities related to Connecticut Valley. Summarized results of operations of the discontinued operations are as follows (in thousands):

	March 31	March 31
	2005	2004
Operating revenues	$-	$-
Operating expenses
Purchased power	-	-
Other operating expenses	-	243
Income tax benefit	-	(85)
Total operating expenses	-	158
Operating loss	-	(158)
Other income, net	-	28
Net loss, net of tax	-	(130)
Gain from disposal, net of $8,729 tax	-	12,386
Income from discontinued operations, net of tax	$-	$12,256

NOTE 12 - SEGMENT REPORTING

The Company's reportable operating segments include: Central Vermont Public Service Corporation ("CV"), which engages in the purchase, production, transmission, distribution and sale of electricity in Vermont. Custom Investment Corporation is included with CV in the table below; Catamount Energy Corporation ("Catamount"), which invests in unregulated, energy generation projects in the United States and the United Kingdom, and All Other, which includes operating segments below the quantitative threshold for separate disclosure. These operating segments include: 1) Eversant Corporation ("Eversant"), which engages in the sale or rental of electric water heaters through a subsidiary, SmartEnergy Water Heating Services, Inc., to customers in Vermont and New Hampshire; 2) C. V. Realty, Inc., a real estate company whose purpose is to own, acquire, buy, sell and lease real and personal property and interests therein related to the utility business, and 3) Catamount Resources Corporatio n, which was formed to hold the Company's subsidiaries that invest in unregulated business opportunities.

The accounting policies of operating segments are the same as those described in the summary of significant accounting policies. Intersegment revenues include revenues for support services, including allocations of software systems and equipment, to Catamount and Eversant. Financial information by industry segment for the first quarters of 2005 and 2004 is as follows (in thousands):

THREE MONTHS ENDED MARCH 31
	CV VT	Catamount Energy Corporation	All Other	Discontinued Operations	Reclassification and Consolidating Entries	Consolidated
2005
Revenues from external customers	$75,643	$1,140	$457	-	$(1,597)	$75,643
Intersegment revenues	22	-	-	-	(22)	-
Equity in earnings - utility affiliates (1)	483	-	-	-	-	483
Equity in earnings - non-utility affiliates (2)	-	932	-	-	-	932
Rate Order charge (3)	21,771	-	-	-	-	21,771
(Loss) income from continuing operations	(4,937)	188	122	-	-	(4,627)
Total assets at March 31, 2005	487,477	55,098	4,288	-	(2,780)	544,083
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2004
Revenues from external customers	$84,114	$1,016	$469	-	$(1,485)	$84,114
Intersegment revenues	24	-	-	-	(24)	-
Equity income - utility affiliates (1)	215	-	-	-	-	215
Equity income - non-utility affiliates (2)	-	1,473	-	-		1,473
(Loss) income from continuing operations	(2,604)	581	117	-	-	(1,906)
Income from discontinued operations, net of tax    (including gain on disposal of $12,386)	-	-	-	$12,256	-	12,256
Total assets at December 31, 2004	487,567	61,029	15,247	-	(17,080)	546,763

1. See Note 2 herein for CV's investments in affiliates.
2. See Note 3 herein for CV's investment in non-utility affiliates.
3. See Note 9 herein for Retail Rates.

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

In this section we discuss the general financial condition and results of operations for Central Vermont Public Service Corporation (the "Company" or "we" or "our" or "us") and its subsidiaries. Certain factors that may impact future operations are also discussed. Our discussion and analysis is based on, and should be read in conjunction with, the accompanying Condensed Consolidated Financial Statements.

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

• the actions of regulatory bodies;
• performance of the Vermont Yankee nuclear power plant;
• effects of and changes in weather and economic conditions;
• volatility in wholesale power markets;
• ability to maintain our current credit ratings;
• performance of our unregulated businesses; and
• other considerations such as the operations of ISO-New England, changes in the cost or availability of capital, authoritative accounting guidance and the effect of the volatility in the equity markets on pension benefit and other costs.

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

EXECUTIVE OVERVIEW

We are a Vermont-based electric utility that transmits, distributes and sells electricity and invests in renewable and independent power projects. We are regulated by the Vermont Public Service Board ("PSB"), the Connecticut Department of Public Utility and Control and the Federal Energy Regulatory Commission ("FERC"), with respect to rates charged for service, accounting, financing and other matters pertaining to regulated operations. On January 1, 2004, our wholly owned regulated subsidiary, Connecticut Valley, sold its plant assets and franchise to Public Service Company of New Hampshire ("PSNH"). Our wholly owned unregulated subsidiaries include: Catamount Energy Corporation ("Catamount"), which invests primarily in wind energy projects in the United States and United Kingdom; and Eversant Corporation ("Eversant"), which operates a rental water heater business through its subsidiary, SmartEnergy Water Heating Services, Inc.

On March 29, 2005, the PSB issued its Order ("Rate Order") on the rate investigation and our request for a rate increase. The PSB concluded that our rates were higher than is just and reasonable, and must be reduced. See Retail Rates discussion below for additional information. The Rate Order has had a significant impact on our first quarter 2005 results, and will impact this year's annual earnings to a large degree. The immediate impact to earnings is a $21.8 million, or $11.2 million after-tax, unfavorable effect on earnings in the first quarter of 2005. In total, we had a first quarter 2005 consolidated loss of $4.6 million, or 39 cents per diluted share of common stock, compared to first quarter 2004 earnings of $10.4 million, or 82 cents per diluted share of common stock. Our first quarter 2005 results compared to the same period in 2004 are explained in detail in Results of Operations below.

Pursuant to the Rate Order our retail rates were reduced by 2.75 percent beginning April 1, 2005, our allowed return on equity was reduced from 11 percent to 10 percent, and we are required to refund to customers about $6.5 million, including carry costs, in June 2005. In the near term we have sufficient cash on hand, including available-for-sale securities, to maintain operations. However without a combination of ongoing cost reductions and a rate increase within the next eighteen months, our ongoing liquidity will be greatly impacted. Currently, we are seeking to obtain a $20 to $25 million line of credit to help ensure liquidity is maintained over the near-term. Additionally, as a result of the Rate Order, S&P placed our corporate credit rating on Creditwatch with negative implications. These matters are discussed in more detail in Liquidity and Capital Resources below.

We are in the process of implementing a comprehensive action plan to address the issues before us. Management has also identified opportunities for cost reductions totaling $0.75 million in 2005. At the same time, we are in the process of identifying ongoing cost cuts to provide longer-term financial stability for the utility in 2006 while maintaining customer service and reliability. At some point, given inflationary cost pressures, we will have to file a new rate case.

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Given the Rate Order outcome, we have decided not to make any additional investments in Catamount this year. However, 2005 is a critical year in Catamount's wind development strategy. To ensure Catamount can achieve its development goals, we extended a bridge loan up to $14.8 million to continue construction of the 135-megawatt Sweetwater 3 project in Texas. This project is expected to reach financial close in early May 2005.

Catamount is pursuing a loan secured by cash flow from its Sweetwater equity investments so that it is able to repay the loan this year. In addition, Catamount is seeking an equity partner to pursue future growth opportunities. See discussion of Liquidity and Capital Resources and Diversification below for additional information.

RETAIL RATES
On April 7, 2004, the PSB issued an order to investigate our retail rates. On July 15, 2004, we filed a cost of service study pursuant to the rate investigation, and filed a request for a 5.01 percent rate increase, effective April 1, 2005. We also requested that the two cases be consolidated; that request was later approved by the PSB. In October 2004, both the DPS and AARP, interveners in the case, filed testimony with the PSB. Technical hearings with the PSB began in early November 2004, and hearings and filings continued through February 2005.

In filings with the PSB on February 11 and 16, 2005, the DPS requested: 1) a rate refund or credit to ratepayers retroactive to April 1, 2004 of about 6 percent or $16 million; 2) a rate reduction of about 7 percent or $19 million effective with service rendered April 1, 2005; and 3) an 8.75 percent rate of return on common equity. While supporting the DPS position, AARP proposed the following modifications: 1) a 10 percent rate of return on common equity; 2) amortize deferred debits over a six-year period (the DPS recommended a three-year period); and 3) exclude costs associated with, or resulting from, the Connecticut Valley asset sale from our cost of service.

On February 18, 2005, the PSB approved our request for an Accounting Order that allowed for deferral of 2004 utility earnings in excess of an 11 percent return on equity. Per the Accounting Order, we reduced 2004 utility earnings by about $2.3 million after-tax to achieve the 11 percent, and recorded an offsetting pre-tax regulatory liability of $3.8 million to be used or accounted for as the PSB shall determine in its final order.

The last PSB hearing was held on February 18 and the parties filed reply briefs on February 28, 2005. We believed our reply brief supported that 1) a rate reduction for the period April 1, 2004 through March 31, 2005 would not be just or reasonable, and 2) a 2.9 percent rate increase beginning April 1, 2005 was justified. The reduction in the requested rate increase from 5.01 percent to 2.9 percent was based on terms of the power cost settlement reached with the DPS and application of deferred 2004 earnings to reduce deferred charges eligible for rate recovery. Both of these items required approval by the PSB.

On March 29, 2005, the PSB issued its Order ("Rate Order") on the rate investigation and our request for a rate increase. The PSB concluded that our rates were higher than is just and reasonable, and must be reduced. In its Order, the PSB determined the annual revenue requirement beginning April 1, 2004, established rates retroactive to April 7, 2004 and established new rates beginning April 1, 2005. The Rate Order included, among other things, the following: 1) a 1.88 percent rate reduction beginning April 1, 2005; 2) a $3.3 million dollar refund to customers, 3) a 10 percent return on equity (reduced from 11 percent); and 4) a requirement that the gain resulting from the 2004 sale of Connecticut Valley's assets be applied to the benefit of ratepayers to compensate for increased costs. We were also required to file a compliance filing by April 1, 2005 and file a new rate design within 90 days of the Rate Order.

The PSB finalized the rate refund and rate reduction amounts in its April 4, 2005 Compliance Order. The rate refund amounts to about $6.5 million pre-tax and the rate reduction amounts to 2.75 percent ($7.2 million pre-tax on an annual basis).

For accounting purposes, the Rate Order resulted in a $21.8 million, or $11.2 million after-tax, unfavorable effect on utility earnings in March 2005. The primary components of the charge to earnings include: 1) a revised calculation of overearnings for the period 2001 - 2003; 2) application of the gain resulting from the Connecticut Valley sale to reduce costs; 3) a customer refund for over-collections for the period April 7, 2004 through March 31, 2005; and 4) amortization of costs and other adjustments required in the Rate Order. These are described in more detail below (all on a pre-tax basis).

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1. Per our July 2001 PSB-approved rate settlement, utility earnings were capped at 11 percent for the periods 2001 - 2003. We used a common-equity-based calculation methodology to calculate utility earnings for those periods, which resulted in overearnings of $0 in 2001, $0.7 million in 2002 and $2.5 million in 2003. In 2002 and 2003, we reduced utility earnings to achieve the 11 percent cap and recorded offsetting regulatory liabilities to be addressed in the next rate proceeding. In the Rate Order, the PSB determined that while our calculation methodology was not incorrect and was reasonable given the language in the 2001 rate settlement, a cost-of-service based calculation methodology was more consistent with traditional ratemaking practice. Therefore, the PSB required that we recalculate utility earnings for 2001 - 2003 using a cost-of-service-based methodology.

Based on the recalculation, utility earnings above the 11 percent cap amounted to $2.9 million in 2001, $5.7 million in 2002 and $5.3 million in 2003. The difference in methodologies resulted in overearnings of $10.8 million plus $1.3 million in additional carrying costs for the period 2001 -2003. The Rate Order requires that we amortize the resulting $15.3 million regulatory liability, which includes amounts previously deferred, over a four-year period ($3.8 million annually) beginning April 1, 2004.

In March 2005, we recorded a net $8.3 million charge to earnings. This included a $10.8 million charge to operating expense and $1.3 million to interest expense, offset by amortization of $3.8 million.

2. Per the Rate Order, we are required to apply the 2004 gain on the Connecticut Valley asset sale to the benefit of ratepayers through amortizations over a three-year period beginning April 1, 2004. The PSB determined that ratepayers should be compensated for additional costs resulting from the sale, because it included recovery of these costs in the annual revenue requirement beginning April 1, 2004 and the new rates beginning April 1, 2005. The additional costs represent common infrastructure costs that were previously allocated or charged to Connecticut Valley through a service contract.

The PSB's calculation amounts to $6.6 million, which is the difference between the $21 million we received for termination of the long-term power contract with Connecticut Valley and a $14.4 million loss accrual. The loss accrual represented Management's best estimate of the difference between expected future sales revenue, in the wholesale market, for the purchased power that was formerly sold to Connecticut Valley and the cost of purchased power obligations. We recorded these items in the first quarter of 2004.

In March 2005, we recorded a net $4.4 million charge to earnings. This included a $6.6 million charge to operating expense, offset by amortization of $2.2 million.

3. The Rate Order, with revisions from the PSB's Compliance Order, requires a customer refund amounting to about $6.2 million ($3.3 million after-tax) and carrying costs of $0.3 million based on a lump-sum refund. The refund represents over-collections from customers for April 7, 2004 though March 31, 2005 ($1.7 million is attributed to 2005 and $4.5 million is attributed to 2004). On April 25, 2005, the PSB approved a proposal for a lump-sum refund to customers in June 2005 billings. Additionally, on April 25, 2005, the PSB approved application of the $3.8 million regulatory liability for 2004 overearnings (see discussion of February 18, 2005 Accounting Order above) to the refund liability.

In March 2005, we recorded a net $2.7 million charge to earnings. This included a $6.2 million reduction in revenue and a $0.3 million increase in other interest expense, offset by reversal of the $3.8 million regulatory liability.

4. Other adjustments required in the Rate Order resulted in a $6.4 million unfavorable effect on utility earnings. These adjustments were primarily related to adjusting and amortizing certain deferred charges and credits beginning April 1, 2004, because the PSB included recovery of these costs in determining the annual revenue requirement for April 1, 2004 through March 31, 2005. Amortizations result in the matching of expenses to the period in which the amounts are recovered in rates.

The primary components of the net $6.4 million charge to earnings in March 2005 are as follows:

• a $2.4 million increase in purchased power expense mostly related to expensing of Yankee Atomic incremental dismantling costs and Vermont Yankee 2004 replacement energy costs to reflect rate recovery beginning April 1, 2004;
• a $3.2 million increase in operating expenses mostly related to amortization of Vermont Yankee (non-tax) sale-related costs, Vermont Yankee 2002 fuel rod costs and Yankee Atomic dismantling costs to reflect rate recovery beginning April 1, 2004;

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• a $0.8 million decrease in interest income to adjust carrying costs related to Vermont Yankee (non-tax) sale-related costs and Vermont Yankee 2002 fuel rod costs due to rate recovery beginning April 1, 2004;
• a $0.4 million increase in other deductions for disallowance of a portion of Vermont Yankee 2002 fuel rod costs; offset by
• a $0.4 million decrease in other interest expense related to various other adjustments per the Rate Order.

The Rate Order impact on the Condensed Consolidated Statement of Income is shown in the table below. See Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits for the impact on the Condensed Consolidated Balance Sheet.

On April 12, 2005, we filed with the PSB a Request for Reconsideration of the Rate Order. Specific items for reconsideration included: 1) treatment of the costs and benefits associated with the January 1, 2004 Connecticut Valley sale; 2) the 10 percent return on equity; and 3) various other matters for clarification.

On April 12, 2005, the DPS filed with the PSB a Motion for Reconsideration of the Rate Order. Specific items for reconsideration included: 1) treatment of costs formerly recovered by the Company through our service contract with Connecticut Valley; and 2) certain adjustments related to the calculation of overearnings for 2001 - 2003.

We, the DPS and AARP submitted responses to these motions by April 26, 2005 as required by the PSB. If any of the motions are successful, it could result in a change in both the refund and rate decrease amounts. We expect the PSB to respond to this motion in May 2005. We are also evaluating an appeal of the Rate Order with the Vermont Supreme Court, and will reach a conclusion on that course of action after the PSB responds to the Motions for Reconsideration. We are not able to predict the outcome of these matters at this time.

Income Statement Impacts of the Rate Order:

The table below reflects the unfavorable impacts of the Rate Order on specific line items of the Condensed Consolidated Statement of Income for the first quarter of 2005 on a pre-tax basis (in millions).

Income Statement Line Item
Operating Revenue (#3 above)	$(6.2)
Purchased Power (#4 above)	(2.5)
Other Operation (#1, 2, 3 and 4 above)	(10.7)
Other Income (#4 above)	(0.8)
Other Deductions (#4 above)	(0.4)
Other Interest (#1, 3 and 4 above)	(1.2)
Total Rate Order Impact	$(21.8)

LIQUIDITY AND CAPITAL RESOURCES

At March 31, 2005, we had cash and cash equivalents of $22.7 million and working capital of $60.1 million. During the first three months of 2005, cash and cash equivalents increased by $10.9 million. The increase resulted from the following:

Operating Activities:  Operating activities provided $11.7 million, including $5.9 million used by Catamount for notes receivable associated with the purchase of wind turbines.

Investing Activities:  Investing activities provided $1.9 million that primarily included a $22.6 million Catamount note repayment related to the Sweetwater 2 project, offset by $3.4 million of construction expenditures, $15.7 million of non-utility investments and a net investment of $1.7 million in available-for-sale securities.

Financing Activities:  Financing activities used $2.7 million primarily related to dividends paid on common and preferred stock, and restricted cash of $2.0 million provided funds to retire preferred stock.

At March 31, 2005, investments in available-for-sale securities included $29.5 million with maturities from 90 days up to one year and $12.9 million with maturities greater than one year.

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VELCO:  We are considering continued investments in Vermont Electric Power Company's ("VELCO") planned transmission upgrades. Our investments in VELCO will maintain VELCO's common equity at 25 percent of its total capitalization. VELCO will require additional equity capital beyond 2005 in order to finance all of the proposed transmission upgrades and we will consider additional investments in VELCO at that time. We may invest about $6.0 million in the third quarter of 2005. In total, our investments in VELCO could amount to between $30 million and $35 million through 2007. Our investment plans in VELCO are subject to change due to liquidity deterioration resulting from the Rate Order.

Catamount:  Catamount has sufficient cash flow to cover its ongoing operating expenses. In April 2005, to ensure Catamount can achieve its development goals, we extended a bridge loan up to $14.8 million. Additional project investments that will allow Catamount to execute its growth strategy will require third party financing and an equity investor. We do not plan to make investments in Catamount for the foreseeable future.

Rate Order:  Our retail rates were reduced by 2.75 percent ($7.2 million pre-tax on an annual basis) on April 1, 2005. Additionally we expect the $6.5 million pre-tax customer refund, mostly through credits on customer bills, to occur in the second quarter of 2005. Both of these items will have a direct impact on our cash flow from operations in 2005, and the rate reduction combined with the 10 percent return on equity (reduced from 11 percent) will impact our cash flow from operations in future years. See Retail Rates above for additional information.

We believe that cash on hand, including available-for-sale securities, and cash flow from operations will be sufficient to fund our business for the near term, although, Vermont utility cash flow from operations will decrease in 2005 when compared to 2004. 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; and increases in net power costs largely due to lower-than-anticipated margins on sales revenue from excess power.

Financing
Utility Based on outstanding debt at March 31, 2005, no principal payments are due on long-term debt from 2005 through 2007. Substantially all utility property and plant are subject to liens under the First Mortgage Bond indenture. Currently, we are not in default under any of our debt financing documents.

At March 31, 2005, we were in compliance with all covenants related to our various debt agreements, Articles of Association and letters of credit; these agreements contain financial and non-financial covenants.

Currently we are seeking to obtain a $20 to $25 million line of credit to help ensure liquidity is maintained over the near-term.

Non-Utility As part of its wind development efforts, Catamount expects to be an equity participant in a wind farm located in Nolan County, Texas known as Sweetwater 3. Construction close on Sweetwater 3 is expected to occur in early May 2005 and as a result Catamount will be required to post $24.8 million of security, representing Catamount's expected equity contribution, to be maintained in pledged collateral accounts for the construction lender. At construction close, Catamount will be reimbursed by the Sweetwater 3 project for cumulative payments of $11.8 million made through March 2005 under the turbine supply agreement as described below and $0.2 million for other Sweetwater 3 related project costs. Catamount will fund the $24.8 million security with the $12.0 million of reimbursements and $12.8 million from the bridge loan extended by the Company in April 2005.

In November 2004, Catamount entered into an agreement with a third-party developer for the purchase of wind turbines for a joint-development project. Pursuant to the agreement, Catamount made a total of $5.9 million of payments to the turbine supplier in 2004 and a $5.9 million payment in March 2005. The turbine supply agreement calls for a payment of $14.8 million in September 2005, with the remaining contract amount of $32.5 million due based on milestones established in the agreement. When the Sweetwater 3 construction financing is complete, the September 2005 and remaining contract amount will be assumed by the Sweetwater 3 project, pursuant to the construction financing agreement.

Catamount has solicited offers from selected financial institutions for a credit facility to be secured by its Sweetwater equity investments. Catamount expects to close on a facility in the second quarter of 2005 and expects to use the proceeds to payoff the $12.8 million bridge loan that we extended to Catamount in April 2005. While Catamount expects to close on a credit facility in the second quarter of 2005, there can be no assurance that Catamount will be successful in securing a credit facility in the desired timeframe. In addition, Catamount is seeking capital from an equity investor or partner in 2005, and a portion of those proceeds could be used to fully repay the bridge loan.

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Credit Ratings
Following the rate decision, Standard & Poor's Ratings Services ("S&P") placed our corporate credit rating on "CreditWatch with negative implications." S&P said that it expects to resolve the CreditWatch listing once we adjust our plans for future capital expenditures and operating and maintenance expenditures in light of the rate reduction. While Fitch Ratings ("Fitch") did not take any immediate action, they also expressed concern about this decision.

Our current corporate credit rating with S&P is BBB-. Our first mortgage debt is rated at BBB+ by both S&P and Fitch. In general, a downgrade would increase our borrowing costs and could hamper our operational flexibility by restricting access to capital and imposing additional requirements to provide performance assurance associated with certain power purchase and sale transactions. We believe that we have sufficient liquidity to meet the performance assurance requirements as described below if the need arises. A downgrade would also increase the costs of our three letters of credit and our vehicle lease costs about $0.1 million.

Currently, we are subject to performance assurance requirements associated with our power purchase and sale transactions through ISO-New England under the Financial Assurance Policy for NEPOOL members. While we are generally a net seller to ISO-New England, in limited circumstances, we must post collateral if the net amount owed exceeds our credit limit at ISO-New England. A Company's credit limit is calculated as a percentage, based on its credit rating, of its net worth. At our current credit rating of BBB-, our credit limit with ISO-New England is about $2.7 million. We have not had to post any collateral with ISO-New England in 2005. If we are downgraded to below investment grade status, our credit limit with ISO-New England will go to zero and we will be required to post collateral for all net purchase transactions. Based on recent trading experience, we estimate that we could be required to post about $3.0 million of collateral with ISO-New England if we were to be in a net purchase position w ith ISO-New England after being downgraded to below investment-grade status.

We are also subject to performance assurance requirements under our Vermont Yankee power purchased contract (the 2001 Amendatory Agreement). If Entergy Nuclear Vermont Yankee, LLC ("ENVY"), the seller, has commercially reasonable grounds for insecurity regarding our ability to pay for our monthly power purchases, ENVY may ask Vermont Yankee Nuclear Power Corporation ("VYNPC") and VYNPC may then ask us to provide adequate financial assurance of payment. We have never had to post collateral under this contract.

At March 31, 2005, we were also selling power in the wholesale market pursuant to two third-party contracts. Under both of these contracts, we would be required to post collateral if downgraded below investment-grade status, but only if required to do so by the counterparties. If downgraded, we estimate that we could be required to post collateral of up to about $11.0 million under these two contracts, based on current forward market prices. Depending on the difference between the contract price and the market price of power, this estimate could increase or decrease accordingly.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our financial statements are prepared in accordance with accounting principles generally accepted in the United States ("GAAP"), requiring us to make estimates and judgments that affect reported amounts of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of the Condensed Consolidated Financial Statements. See Critical Accounting Policies and Estimates in Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report filed on Form 10-K for a discussion of the estimates and judgments necessary in our accounting for regulation, unregulated business, revenues, income taxes, loss accruals, pension and postretirement benefits and other matters. The following is an update to the 2004 Form 10-K.

Regulation We prepare our financial statements in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71, Accounting for the Effects of Certain Types of Regulation ("SFAS No. 71"), for our regulated Vermont service territory and FERC-regulated wholesale business. Although the Rate Order had a significant unfavorable effect on our financial position and results of operations for the period ended March 31, 2005, our regulatory business continues to meet the criteria for accounting under SFAS No. 71. Based on a current evaluation of the factors and conditions expected to impact future cost recovery, Management believes future recovery of its regulatory assets in the State of Vermont for its retail and wholesale businesses is probable.

If we determine that the Company no longer meets the criteria under SFAS No. 71 and there is not a rate mechanism to recover these costs, the accounting impact would be an extraordinary charge to operations of about $26.3 million pre-tax as of March 31, 2005.

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Unregulated Business Catamount evaluates the carrying value of its investments on a quarterly basis, or when events and circumstances warrant. The carrying value is considered impaired when the anticipated fair value, based on undiscounted cash flows, is less than the carrying value of each investment. In that event, a loss is recognized based on the amount by which the carrying value exceeds the fair value of the investment.

In the first quarter of 2005, Catamount determined that its equity investment in Rumford Cogeneration Company ("Rumford") was impaired; however the impairment was determined to be temporary. Management's assessment was based on the fact that the electric energy rate, a critical component in determining whether an impairment has occurred is currently being negotiated between the affected parties. Catamount prepared several scenarios based on varying electric energy prices and other assumptions which resulted in a range of possible outcomes from no impairment to an impairment of $1.7 million. At this time, Management does not believe any one scenario has a higher probability of occurrence than the others and therefore has concluded the impairment is temporary. Catamount also determined that first quarter 2005 equity earnings from its German wind projects were impaired by an amount of less than $0.1 million based on a non-binding offer from a third party to purchase the projects. There were no equity in vestment impairments in the first quarter of 2004.

Investments in Marketable Securities We account for investments in marketable equity and debt securities in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities ("SFAS No. 115"). At March 31, 2005, all of our marketable securities were classified as available-for-sale and reported at fair value. Unrealized gains and losses are reported as a component of accumulated other comprehensive income (loss), net of tax, in common stock equity. The carrying cost of debt securities is adjusted for amortization of premiums and accretion of discounts from the date of purchase to maturity.

We evaluate the carrying value of our investments on a quarterly basis, or when events and circumstances warrant, determining whether a decline in fair value should be considered other-than-temporary. The carrying value is considered impaired when the anticipated fair value, based on cash flow forecasts is less than the carrying value of each investment. In that event, a realized loss is recognized based on the amount by which the carrying value exceeds the fair value of the investment. We follow our investment managers' methods of determining the cost basis in computing realized gains and losses on the sale of our available-for-sale securities. These realized gains and losses are included in other income or deductions.

We use several criteria to evaluate other-than-temporary declines, including 1) length of time and the extent to which the market value has been less than cost; 2) financial condition and near-term prospects of the issuer; and 3) our intent and ability to retain the investments for a period of time sufficient to allow for any anticipated recovery in market value. In the first quarter of 2005, we recorded $0.1 million of realized losses and $0.3 million for impairment of certain available-for-sale investments based on our intent to liquidate certain securities prior to their original maturity dates. Based upon forecasted cash flow needs, the security closest to its maturity was chosen. Generally, a security close to its maturity date should have less pricing volatility due to interest rate movements than one further from its maturity date. See Note 6 - Investment Securities for additional information.

Pension and Postretirement Benefits Pension costs were $1.1 million in the first quarter of 2005, of which $0.9 million is reflected in results of operations and the remaining amount was capitalized. This compares to pension costs of $0.8 million in the first quarter of 2004, of which $0.7 million was reflected in results of operations and the remaining amount was capitalized.

Postretirement costs were $0.7 million in the first quarter of 2005, of which $0.6 million is reflected in results of operations and the remaining amount was capitalized. This compares to postretirement costs of $0.8 million in the first quarter of 2004, of which $0.7 million was reflected in results of operations and the remaining amount was capitalized.

Pension costs and cash funding requirements are expected to increase in future years. As of March 31, 2005, the market value of pension plan trust assets was $62.8 million, including $42.3 million in marketable equity securities and $20.5 million in debt securities. Pension plan trust assets were $64.2 million at December 31, 2004, including $44.3 million in marketable equity securities and $19.9 million in debt securities.

Reserve for Loss on Power Contract In accordance with the requirements of SFAS No. 5, Accounting for Contingencies, ("SFAS No. 5") in the first quarter of 2004, we recorded a $14.4 million pre-tax loss accrual related to termination of our long-term power contract with Connecticut Valley. The contract was terminated in the first quarter of 2004, as a condition of the Connecticut Valley sale described in Discontinued Operations below. The loss

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accrual represented Management's best estimate of the difference between expected future sales revenue, in the wholesale market, for the purchased power that was formerly sold to Connecticut Valley and the cost of purchased power obligations. The estimated life of the power contracts that were in place to supply power to Connecticut Valley extends through 2015.

The loss accrual was estimated based on assumptions about future power prices, the reallocation of power from the state-appointed purchasing agent ("VEPPI") and future load growth. Management reviews this estimate at the end of each reporting period and will increase the reserve if the revised estimate exceeds the recorded loss accrual. The loss accrual is being amortized on a straight-line basis through 2015.

RESULTS OF OPERATIONS
The following is a detailed discussion of the Company's results of operations for the first quarter of 2005 compared to the first quarter of 2004. This should be read in conjunction with the condensed consolidated financial statements and accompanying notes included in this report.

Consolidated Summary:

We had a first quarter 2005 consolidated loss of $4.6 million, or 39 cents per diluted share of common stock, compared to first quarter 2004 earnings of $10.4 million, or 82 cents per diluted share of common stock.A reconciliation of diluted earnings (loss) per share follows.

2004 Earnings per diluted share		$.82
Year over Year Effects on Earnings:
Lower purchased power costs (a)	.20
Catamount - lower earnings	(.03)
Lower retail and firm sales (b)	(.05)
Lower resale sales	(.06)
Other	(.05)
Subtotal		.01
Net impact of March 29, 2005 Rate Order		(.91)
Net impact Connecticut Valley sale recorded in 2004:
Gain on discontinued operations	(1.00)
SFAS No. 5 loss accrual - termination of power contract	.69
		(.31)
2005 Loss per diluted share		(.39)
(a) - Excludes effect of Rate Order and 2004 SFAS No. 5 loss accrual
(b) - Excludes effect of Rate Order

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Condensed Consolidated Income Statement Discussion
The following includes a more detailed discussion of the components of our Condensed Consolidated Statements of Income and related year-over-year variances.

Operating Revenues The majority of our operating revenues are generated through retail sales from the regulated Vermont utility business. Other resale sales are related to the sale of excess power from our owned and purchased power supply portfolio. Operating revenues and related mWh sales for the first quarter of 2005 and 2004 are summarized below:

	mWh Sales                     2005                     2004		Revenues (in thousands)            2005                      2004
Retail Sales:   Residential   Commercial   Industrial   Other Total retail sales	273,678 217,063 109,158     1,331 601,230	282,436 215,453 111,466     1,354 610,709	$35,287  25,706  9,347         393    70,733	$36,185 25,626 9,520        402   71,733
Resale sales:   Firm (1)   Other Total resale sales	1,352 151,180 152,532	1,404 179,196 180,600	61      8,910      8,971	52   10,186   10,238
Retail customer refund	-	-	(6,197)	-
Other revenues	-	-	2,136	2,143
Total	753,762	791,309	$75,643	$84,114
(1) Based on FERC-filed tariffs.

Comparative changes in Operating revenues for the first quarter of 2005 versus 2004 are summarized below:

	2005 vs. 2004
Retail revenues:    Change in mWh volume    Change in price (customer mix)    Subtotal Firm resale sales Other resale sales Retail customer refund Other revenues Decrease in Operating revenues	$(1,134)       134  (1,000) 9  (1,276) (6,197)          (7) $(8,471)

The $8.5 million decrease in Operating revenues is due to the following factors:

• The retail customer refund reduced revenue by $6.2 million. The Rate Order required a refund to customers for over-collections during the period April 7, 2004 through March 31, 2005. Of the $6.2 million, $1.7 million is attributed to 2005 and $4.5 million is attributed to 2004. See Retail Rates above for additional information.
• Retail and firm sales decreased $1 million due to lower sales volume. These sales are affected by economic and weather conditions. Milder winter weather in 2005 compared to 2004 reduced sales volume by 1.5 percent.
• Other resale sales decreased by $1.3 million primarily due to lower sales volume from forward sale contracts, also lower output from our power resources reduced the amount of excess available for resale.

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Purchased Power Most of our power purchases are made under long-term contracts. These contracts, power supply management and nuclear investments are described in more detail in Power Supply Matters below. The primary components of purchased power expense are as follows (in thousands):

	Three Months Ended March 31,         2005                  2004
VYNPC (a) Hydro-Quebec Independent Power Producers ("IPPs")      subtotal long-term contracts Short-term purchases Miscellaneous purchases SFAS No. 5 loss accrual (net of amortizations) Nuclear decommissioning costs March 29, 2005 Rate Order Other Total purchased power	$15,216  15,171      4,569  34,956  3,919  13  (299) 790  2,441         28  $41,848	$17,488  15,313      5,487  38,288  4,906  20  14,052  597  -          59  $57,922
(a) Includes about $0.4 million in 2005 related to insurance refunds that we deferred per PSB approval. See Note 4 -      Regulatory Assets, Deferred Charges and Deferred Credits.

The related mWh purchases and unit price from these sources are summarized below:

	Three Months Ended March 31,            2005                                                2004
	mWh	$/mWh	mWh	$/mWh
VYNPC Hydro-Quebec IPPs Short-term purchases Miscellaneous purchases Total mWh	379,974 228,916 32,958 37,394        480 679,722	$40.04 $66.27 $128.62 $104.80 $27.08	400,734 237,523 42,025 41,321       685 722,288	$43.64 $64.47 $130.57 $118.73 $29.20

Purchased power expense decreased $16.1 million in the first quarter of 2005 compared to the same period of 2004 due to the following factors:

• A $14.4 million favorable impact related to the SFAS No. 5 loss accrual that we recorded in the first quarter of 2004. The loss accrual was related to termination of the power contract with Connecticut Valley and represented Management's best estimate of the difference between expected future sales revenue, in the wholesale market, for the purchased power that was formerly sold to Connecticut Valley and the cost of purchased power to be incurred to realize those future sales. In accordance with GAAP, the loss accrual is being amortized on a straight-line basis through 2015, which represents the estimated life of our power contracts that were in place to source the Connecticut Valley power contract. Amortizations reduced purchased power expense by about $0.3 million in the first quarters of 2005 and 2004.
• Long-term purchases decreased $3.3 million primarily related to lower energy prices under the Vermont Yankee purchased power contract, lower Vermont Yankee plant output and lower output from IPPs.
• Short-term purchases decreased about $1 million due to lower volume and lower average prices in 2005.
• Accounting entries related to the Rate Order, described in Retail Rates above, increased purchased power expense by about $2.5 million mostly related to Yankee Atomic incremental dismantling costs and Vermont Yankee replacement energy costs related to a 2004 unscheduled outage.
• Nuclear decommissioning costs are related to our share of Maine Yankee, Connecticut Yankee and Yankee Atomic decommissioning costs. Our share of decommissioning costs increased $0.2 million, due to changes in FERC-approved rates in 2004.

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Operating Expenses Operating expenses represent costs incurred to support our core business. The table below provides the variances in income statement line items for Operating Expenses on the Condensed Consolidated Statements of Income for the first quarter of 2005 versus the same period in 2004, including the impact of the Rate Order (in thousands).

	2005 over / (under) 2004
	Related to	Related to
	Operations		Rate Order	Total Variance	Percent
Operation
Purchased power (explained above)	$(18,515)		$2,441	$(16,074)	(27.8)%
Production and transmission	551		-	551	8.3
Other operation	491		10,739	11,230	100.6
Maintenance	(21)		-	(21)	(0.6)
Depreciation	37		-	37	0.9
Other taxes, principally property taxes	159		-	159	4.6
Taxes on income	5,959		(10,022)	(4,063)	(194.8)
Total operating expenses	$(11,339)		$3,158	$(8,181)	(9.7)%

Production and transmission: These expenses are primarily associated with generating electricity from our wholly and jointly owned units, and transmission of electricity. The $0.6 million increase in 2005 is primarily related to higher ISO-New England transmission costs due to higher rates and other charges.

Other operation: These expenses are primarily related to operating activity such as regulatory deferrals and amortizations, customer accounting, customer service, administrative and general and other operating costs incurred to support our core business. The $10.7 million related to the Rate Order primarily resulted from the calculation of overearnings for 2001 - 2003 as described in Retail Rates above. The remaining $0.5 million increase resulted from higher pension and bad debt expense, offset by lower employee-related costs such as active employee and retiree medical costs.

Taxes on Income: Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences and changes in valuation allowances for the periods. The effective tax rate was 57.1 percent for the first quarter of 2005 compared to 40.6 percent for the same period in 2004, reflecting the effect of the Rate Order in the first quarter of 2005. Significant items that affected taxes on income in the first quarters of 2005 and 2004 are described below.

Rate Order: In March 2005, we recorded a $21.8 million pre-tax, or $11.2 million after-tax, charge to utility earnings due to the Rate Order. The related $10.0 million net income tax benefit includes a $1.6 million favorable impact resulting from a higher projected 2005 income tax rate. The remaining $0.6 million benefit is included in Benefit (provision) for income taxes below.

Discontinued Operations: In the first quarter of 2004, taxes on income included a $5.9 million benefit related to the loss accrual resulting from the termination of the power contract with Connecticut Valley as described in DiscontinuedOperations below.

Other Income and Deductions These items are related to the non-operating activities of the utility business and the operating and non-operating activities of our non-regulated businesses. The variances in income statement line items for Other Income and Deductions on the Condensed Consolidated Statements of Income for the first quarter of 2005 versus 2004 are shown in the table below (in thousands). Impacts of the Rate Order are shown separately.

	2005 over / (under) 2004
	Related to Operations	Related to Rate Order	Total variance	Percent
Equity in earnings of affiliates	$268	-	$268	124.3%
Equity in earnings of non-utility investments	(541)	-	(541)	(36.7)
Allowance for equity funds during construction	(16)	-	(16)	(54.1)
Other income	(6)	$(822)	(828)	(32.7)
Other deductions	(849)	(403)	(1,252)	(53.5)
Benefit (provision) for income taxes	(58)	598	540	101.0
Total other income and deductions	$(1,202)	$(627)	$(1,829)	(133.6)%

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Equity in earnings of affiliates: These are related to our equity investments, primarily VELCO and Vermont Yankee Nuclear Power Corporation ("VYNPC"). The $0.3 million increase is primarily related to higher VELCO earnings.

Equity in earnings of non-utility investments: These are related to Catamount's equity investments in non-regulated independent power projects. The $0.5 million decrease is primarily due Catamount's investment in Appomattox in which the project lease expired in November 2004, partially offset by higher earnings from Sweetwater 1 and the sale of Rupert and Glenns Ferry in July 2004.

Other income: These income items include interest and dividend income, interest on temporary investments and non-utility notes receivable, Catamount's operating revenue, regulatory asset carrying costs, amortization of contributions in aid of construction and various miscellaneous other income items. The $0.8 million decrease related to the Rate Order reflects required adjustments to carrying charges for deferred Vermont Yankee sale costs and Vermont Yankee fuel rod costs as described in Retail Rates above.

Other Deductions: These deductions include Catamount's operating expenses, impairment charges related to available for sale securities, supplemental retirement benefits and insurance, including changes in the cash surrender value of life insurance policies, and miscellaneous other deductions.

The $0.4 million increase related to the Rate Order reflects disallowance of a portion of Vermont Yankee fuel rod costs as described in Retail Rates above. The remaining $0.8 million increase includes impairment and realized losses associated with certain available-for-sale debt securities that we no longer intend to hold to maturity, higher other taxes and other miscellaneous items.

Benefit (provision) for income taxes:  Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences and changes in valuation allowances for the periods. For the first quarter of 2005, this includes a tax benefit of $0.6 million associated with the Rate Order.

Interest Expense Interest expense includes interest on long-term debt and other interest of the utility business and our unregulated businesses. The variances in income statement line items for Interest Expense on the Condensed Consolidated Statements of Income for the first quarter of 2005 versus 2004 are shown in the table below (in thousands). Impacts of the Rate Order are shown separately.

	2005 over / (under) 2004
	Related to Operations	Related to Rate Order	Total variance	Percent
Interest on long-term debt	$(639)	-	$(639)	(25.7)%
Other interest	65	$1,168	1,233	686.8
Allowance for borrowed funds during construction	8	-	8	64.0
Total interest expense	$(566)	$1,168	$602	22.7%

Interest on long-term debt: The $0.6 million decrease resulted from lower interest rates due to the August 2004 bond refinancing.

Other interest expense: The $1.2 million increase is primarily related to carrying costs associated with the recalculation of overearnings for 2001 - 2003 as described in Retail Rates above.

Discontinued Operations On January 1, 2004, Connecticut Valley completed the sale of substantially all of its plant assets and its franchise to PSNH. See discussion of Discontinued Operations below.

POWER SUPPLY MATTERS

Sources of Energy We purchase about 90 percent of our power requirements under several contracts, mostly from Hydro-Quebec and VYNPC. The remaining power is supplied by our jointly and wholly owned generating facilities, and short-term purchases. We rely on sales of excess power to help mitigate overall net power costs.

Power Contract Commitments
Hydro-Quebec We purchase varying amounts of power from Hydro-Quebec under the Vermont Joint Owners ("VJO") Power Contract and related contracts negotiated between us and Hydro-Quebec, which extend through 2016. There are specific contractual provisions that provide that in the event any VJO member fails to meet its

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obligation under the contract with Hydro-Quebec, the remaining VJO participants, including us, must "step-up" to the defaulting party's share on a pro rata basis.

VYNPC We have a 35 percent entitlement in Vermont Yankee plant output sold by ENVY to VYNPC, through a long-term power purchase contract with VYNPC. One remaining secondary purchaser continues to receive a small percentage of our entitlement, reducing our entitlement to about 34.83 percent. ENVY has no obligation to supply energy to VYNPC over the amount the plant is producing, so entitlement holders receive reduced amounts when the plant is operating at a reduced level, and no energy when the plant is not operating.

In 2003, ENVY sought PSB approval to increase generation at the Vermont Yankee plant by 110 megawatts. Our purchases from VYNPC will not be affected by increased generation but our entitlement percentage of plant output will decrease to about 29 percent. On March 15, 2004, the PSB approved the proposal, but its approval was conditioned on ENVY providing an outage protection indemnification ("Ratepayer Protection Proposal" or "RPP") for us and GMP in case the uprate causes temporary reductions in output that reduce our value of the PPA. Our maximum right to indemnification under the RPP is about $2.8 million, and will be in place for three years to cover any uprate-related reductions in output.

Plant output has been reduced since the April 2004 scheduled refueling outage, and will continue until ENVY receives NRC approval for the uprate. Our entitlement has been reduced by an average of about 4 MW since that time. The financial effect of such a reduction will be covered under the terms of the RPP. In 2004, ENVY made a payment of an undisputed amount under the RPP and we are seeking agreement with ENVY on a final payment.

ENVY has announced that, under current operating parameters, it will exhaust the capacity of its nuclear waste storage pool in 2007 or 2008 and will need to store nuclear waste in so-called 'dry cask' storage facilities to be constructed on the site. ENVY requires both enabling legislation from the Vermont State Legislature, which is currently under consideration, and PSB approval for dry cask storage. If ENVY is unsuccessful in receiving favorable legislative action and/or regulatory approval, ENVY has announced that it could be required to shut down the Vermont Yankee plant in 2007 or 2008, compared to its current license life of 2012. We are continuing to assess the impacts of an earlier than planned shut down of the Vermont Yankee plant.

Independent Power Producers ("IPPs") We purchase power from a number of IPPs who own qualifying facilities under the Public Utility Regulatory Policies Act of 1978. These qualifying facilities produce energy primarily using hydroelectric and biomass generation. Most of the power comes through a state-appointed purchasing agent, VEPP Inc. ("VEPPI"), which assigns power to all Vermont utilities under PSB rules.

Power Supply Management We engage in short-term purchases and sales in the wholesale markets administered by the New England Independent System Operator ("ISO-New England") and with other third parties, primarily in New England, to minimize net power costs and risks to our customers. On an hourly basis, power is sold or bought through ISO-New England to balance our resource output and load requirements, through the normal settlement process. On a monthly basis, we aggregate the hourly sales and purchases through ISO-New England and record them as Operating Revenue or Purchased Power, respectively.

Our long-term power forecast shows that energy purchase and production amounts exceed our load requirements. This is partly attributed to the January 1, 2004 termination of the power contract with Connecticut Valley, which made an annual average of about 15 MW previously used to source the contract available for load requirements or for resale. Because of this general increase, in November 2004, we entered two separate forward sale transactions, one through October 2006 and one through December 2008.

Beginning May 1, 2004, we began to settle our power accounts with ISO-New England on a standalone (direct) basis. Prior to that, all Vermont utilities were settled at ISO-New England, and VELCO then performed the settlement within Vermont. With changes in power markets and NEPOOL/ISO rules and procedures, many of the benefits of a single Vermont settlement have disappeared, and direct settlement now provides advantages to us in terms of efficiency and cost savings.

Transmission-related matters We operate our transmission system under an open-access tariff, pursuant to FERC Order No. 888. On March 24, 2004, FERC conditionally approved the filing to create an RTO for New England. The RTO parties submitted a compliance filing to FERC in December 2004. In the filing, the Highgate facilities are classified as PTF with a five-year phase-in of Regional Network Service ("RNS") reimbursement treatment. At the end of the phase-in period, our net costs will be based on our load ratio rather than our ownership share of the

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facilities. This change is expected to significantly decrease our costs for RNS service related to that facility. Apart from the new RTO, we expect other transmission costs will increase due to growth in new transmission facilities in New England. The RTO began operations on February 1, 2005. Our share of savings related to the Highgate facilities are expected to be about $0.6 million in 2005, $1.0 million in 2006, $1.4 million in 2007, $1.7 million in 2008 and $2.1 million in 2009. At this time, we are not able to predict the impact of other transmission costs related to the RTO.

Wholly Owned Generating Units We own and operate 20 hydroelectric generating units, two oil-fired gas turbines and one diesel peaking unit with a combined nameplate capability of 73.6 MW.

Peterson Dam In January 2003, we, the Vermont Agency of Natural Resources ("Agency"), Vermont Natural Resources Council and other parties reached an agreement to allow us to relicense the four dams we own and operate on the Lamoille River. According to the agreement, we will receive a water quality certificate from the State, which is needed for FERC to relicense the facilities for 30 years. The agreement also stipulates that subject to various conditions, we must begin decommissioning Peterson Dam in about 20 years. The agreement requires PSB approval of full rate recovery related to decommissioning the Peterson Dam, including recovery of replacement power costs when the dam is out of service. In July 2003, the Agency published its draft water quality certificate and in October 2003, pursuant to the schedule set forth in the agreement, we filed a petition with the PSB for approval of the rate recovery mechanisms. In April 2004, the PSB issued an order adopting a schedule intended to permit a final order in the fourth quarter of 2004. In the second quarter of 2004, at a public hearing, many residents of the Town of Milton opposed the dam's removal. The PSB held two additional public meetings in September 2004, and testimony was given in support of and opposition to removal of the power station. The case has continued to progress through the regulatory process, with some delay, and final technical hearings were held in March and April 2005. A final order is now expected in 2005. We cannot predict the outcome of this matter. 

Nuclear Generating Companies We are one of several sponsor companies with ownership interests in Maine Yankee, Connecticut Yankee and Yankee Atomic, and are responsible for paying our ownership percentage of decommissioning and all other costs for each plant. All three of these nuclear plants have been shut down and are undergoing decommissioning. We also have a joint-ownership interest in Millstone Unit #3. Our obligations related to these plants are described below.

Maine Yankee, Connecticut Yankee and Yankee Atomic: All three companies collect decommissioning and closure costs through wholesale FERC-approved rates charged under power agreements with several New England utilities, including us. Historically, our share of these costs has been recovered from its retail customers through PSB-approved rates. Based on the regulatory process, management believes its share of decommissioning and closure costs for each plant will continue to be recovered through the regulatory process. Although management believes that these costs will ultimately be recovered from its customers, there is a risk that FERC may not allow full recovery of Connecticut Yankee's increased costs in wholesale rates, as described below. If FERC does not allow these costs to be recovered in wholesale rates, we anticipate that the PSB would disallow these costs for recovery in retail rates as well.

Our share of Maine Yankee, Connecticut Yankee and Yankee Atomic estimated costs are reflected on the Condensed Consolidated Balance Sheet as regulatory assets and nuclear decommissioning liabilities (current and non-current). These amounts are adjusted when revised estimates are provided by the companies. At March 31, 2005, we had regulatory assets of about $5.6 million related to Maine Yankee, $12.1 million related to Connecticut Yankee and $4.7 million related to Yankee Atomic. These estimated costs are being collected from our customers through existing retail rate tariffs. See Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits regarding the Rate Order.

Maine Yankee, Connecticut Yankee and Yankee Atomic are seeking recovery of fuel storage-related costs stemming from the default of the United States Department of Energy ("DOE") under the 1983 fuel disposal contracts that were mandated by the United States Congress under the High Level Waste Act. All three are parties to a lawsuit against the DOE seeking damages based on the DOE's default. The trial on determination of damages began on July 12 and ended August 31, 2004. Closing arguments were held in January 2005 and final post-trial briefs were filed in February 2005. The Department of Justice submitted a motion to the court during the damage trial arguing that the spent fuel obligations prior to April 1983 should be treated as an offset to any award of damages. The Court's ruling on that matter is expected to be issued with its overall ruling in the case, which is expected by the end of 2005. None of the plants has included any allowance for potential recovery of these claims in their FERC-filed c ost estimates.

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Maine Yankee: We have a 2 percent ownership interest in Maine Yankee. Beginning November 1, 2004, Maine Yankee's billings to sponsor companies have been based on its September 16, 2004, FERC approved settlement, which provides for recovery of Maine Yankee's forecasted costs of providing service through a formula rate contained in its power contracts through October 31, 2008 and replenishment of the DOE Spent Fuel Obligation through collections from November 2008 through October 2010.

Connecticut Yankee: We have a 2 percent ownership interest in Connecticut Yankee. Costs currently billed by Connecticut Yankee are based on its most recent FERC-filed rates effective February 1, 2005, for collection through 2010. Prior to February 1, 2005, costs were based on FERC-approved rates that became effective September 1, 2000, for collection through 2007.

Connecticut Yankee is currently involved in litigation related to a contract dispute. Also in 2004, Connecticut Yankee filed a rate application with FERC. These matters are discussed in more detail below.

Bechtel Litigation:  Connecticut Yankee is involved in a contract dispute with Bechtel Power Corporation ("Bechtel"), which resulted in termination of the decommissioning services contract between Connecticut Yankee and Bechtel. Connecticut Yankee continues to prosecute its counterclaims and other damages against Bechtel in Connecticut Superior Court. Discovery is underway and a trial has been scheduled for May 2006.

FERC Rate Case Filing:  

On July 1, 2004, Connecticut Yankee filed its December 2003 cost estimate with FERC as part of its rate application ("Filing") seeking additional funding to complete the decommissioning project and for storage of spent fuel through 2023. The proposed annual decommissioning collection represented a significant increase in annual charges to the sponsor companies, including the Company, as compared to prior FERC rates. The Connecticut Department of Public Utility Control ("CT DPUC") has intervened in this rate case alleging Connecticut Yankee imprudence in its decommissioning effort. Bechtel has also intervened.

On August 30, 2004, FERC issued an order: 1) accepting for filing the new charges proposed by Connecticut Yankee in its rate application; 2) suspending these revised charges until February 1, 2005; 3) establishing Administrative Law Judge hearing procedures and schedules; 4) denying the CT DPUC and Connecticut Office of Consumer Counsel ("OCC") request for an accelerated hearing schedule and for a bond or other security for potential refunds; 5) denying the declaratory ruling sought by the CT DPUC and OCC; and 6) granting Bechtel's motion to intervene as well as allowing interventions by other applying parties. On September 7, 2004, a FERC administrative law judge was appointed to the case. The current schedule provides for the hearings to start June 1, 2005. Connecticut Yankee anticipates that the process of resolving the matters in the Filing is likely to be contentious and lengthy.

We continue to believe that FERC will approve recovery of Connecticut Yankee's increased costs in wholesale rates based on the nature of costs and previous rulings at other nuclear companies. Once approved by FERC, we believe it is unlikely that the PSB would not allow these FERC-approved costs to be recovered in retail rates. The timing, amount and outcome of the Bechtel litigation and FERC rate case filing cannot be predicted at this time.

Yankee Atomic: We have a 3.5 percent ownership interest in Yankee Atomic. Costs billed by Yankee Atomic are based on an April 4, 2003 FERC filing, in which FERC approved the resumption of billings starting June 2003 for a recovery period through 2010.

Millstone Unit #3 We have a 1.7303 percent joint-ownership interest in Millstone Unit #3, in which Dominion Nuclear Corporation ("DNC") is the lead owner with about 93.47 percent of the plant joint-ownership. We have an external trust dedicated to funding our joint-ownership share of future decommissioning costs.

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 storage of spent nuclear fuel arising from the failure of the DOE to comply with its obligations to commence accepting such fuel in 1998. The schedule for further proceedings in the lawsuit is not known at this time. Millstone Unit #3 spent fuel from the beginning of commercial operations in 1986 resides in the spent fuel pool, and there is believed to be adequate spent fuel pool storage capability to support expected operations through the end of its current licensed life in 2025. We continue to pay our share of the DOE Spent Fuel assessment expenses levied on actual generation and will share in recovery from the lawsuit, if any, in proportion to its ownership interest.

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DIVERSIFICATION
Catamount Resources Corporation was formed to hold our subsidiaries that invest in unregulated businesses including Catamount and Eversant.

Catamount As of March 31, 2005, Catamount had interests in six operating independent power projects located in Rumford, Maine; East Ryegate, Vermont; Nolan County, Texas; Thuringen, Germany and Mecklenburg-Vorpommern, Germany.

Catamount is wholly focused on development, ownership and asset management of wind energy projects. Depending on prices, capital and other requirements, Catamount will entertain offers for the purchase of certain of its wind electric generating assets and any of its remaining non-wind electric generating assets. Additionally, Catamount is seeking an equity investor to co-invest in Catamount. Management cannot predict whether this strategy will be successful, the timing or outcome of potential future asset sales or whether Catamount will obtain an equity investor to co-invest in Catamount.

Catamount has projects under development in the United States and United Kingdom. In January 2004, Catamount Energy Limited and Catamount Cymru Cyf. issued stock to a third party Norwegian investor thereby diluting Catamount's interest to 50 percent. The issuance resulted in no gain or loss.

In 2004, Catamount entered into a joint development arrangement with Marubeni Power International, Inc. The arrangement represents an exclusive agreement for wind energy development throughout New England, New York and Pennsylvania.

In 2003, Catamount ceased "greenfield" development in Germany to focus development efforts in the United States and United Kingdom. Catamount is currently entertaining offers for the sale of its investments in its German operating wind projects and development company. Management cannot predict whether it will ultimately consummate a sale of both its German operating wind projects and development company.

Catamount Results

Catamount recorded first quarter 2005 earnings of $0.2 million compared to first quarter 2004 earnings of $0.6 million. First quarter 2005 earnings included a $1.0 million contingent based fee related to the sale of the Fibrothetford note receivable in 2004 as compared to the 2004 $0.9 million fee associated with Catamount's United Kingdom development efforts. First quarter 2005 earnings as compared to first quarter 2004 earnings also included lower equity earnings primarily due to the expiration of the Appomattox partnership lease and the sale of the Rupert and Glenns Ferry projects in 2004, and higher administrative expenses offset by lower business development, and miscellaneous and amortization expenses.

Catamount, or its wholly owned subsidiaries provide certain management, accounting and other services to certain entities in which Catamount holds an equity interest. Catamount's revenues (included in Other Income on the Condensed Consolidated Statements of Income) include billings of $0.1 million in the first quarters of 2005 and 2004.

Information regarding certain of Catamount's investments follows.

Sweetwater 2 In February 2005, Catamount paid $15.4 million to acquire an equity interest in Sweetwater Wind 2 LLC, a 91.5-MW wind farm in Nolan County, Texas. Sweetwater Wind 2 LLC commenced commercial operations on February 11, 2005.

Rumford In the first quarter of 2005, Catamount determined that its equity investment in Rumford was impaired; however the impairment was determined to be temporary. Management's assessment was based on the fact that the electric energy rate, a critical component in determining whether an impairment has occurred is currently being negotiated between the affected parties. Catamount prepared several scenarios based on varying electric energy prices and other assumptions which resulted in a range of possible outcomes ranging from no impairment to an impairment of $1.7 million. At this time, Management does not believe any one scenario has a higher probability of occurrence than the others and therefore has concluded the impairment is temporary.

DK Burgerwindpark Eckolstadt and DK Windpark Kavelstorf GmbH&Co. KG (collectively "Eurowind") In the first quarter of 2005, Catamount recorded an impairment of less than $0.1 million related to its Eurowind investments. The impairment reflects Management's best estimate of the current market value of these investments based on a non-binding offer from a third party to purchase the projects.

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Eversant As of March 31, 2005, Eversant had a $1.4 million equity investment, representing a 12 percent ownership interest in The Home Service Store Inc. ("HSS"). HSS has established a network of affiliate contractors who perform home maintenance repair and improvements for its members. Eversant accounts for this investment on the cost basis.

Eversant's wholly owned subsidiary, SmartEnergy Water Heating Services, Inc. ("SEWHS"), engages in the sale or rental of electric water heaters in Vermont and New Hampshire. SEWHS had first quarter earnings of $0.1 million in 2005 and 2004.

BUSINESS RISKS

Regulatory Risk: Historically, electric utility rates in Vermont have been based on a utility's costs of service. As a result, electric utilities are subject to certain accounting standards that apply only to regulated businesses. SFAS No. 71 allows regulated entities, such as the Company, 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. The Company currently complies with the provisions of SFAS No. 71 for its regulated Vermont service territory and FERC-regulated wholesale businesses.  If we determine the Company no longer meets the criteria under SFAS No. 71, the accounting impact would be an extraordinary charge to operations of about $26.3 million on a pre-tax basis as of March 31, 2005, assuming no stranded cost recovery would be allowed through a rate mechanism.

Although not currently under consideration, if retail competition were implemented in our Vermont service territory, we are unable to predict the impact on our revenues, our ability to retain existing customers with respect to their power supply purchases and attract new customers or the margins that will be realized on retail sales of electricity, if any such sales are sought.

Wholesale Power Market Risk: Our material power supply contracts and arrangements are principally with Hydro-Quebec and VYNPC. These contracts support the majority of our total annual energy (mWh) purchases. Our exposure to market price volatility is limited for power supply purchases given that our long-term power forecast reflects energy amounts in excess of that required to meet load requirements. However, if one or both of these sources becomes unavailable for an extended period of time, we would be subject to wholesale power price volatility and that amount could be material. Additionally, we rely on the sale of our excess power to help mitigate overall net power costs and price risk. The volatility of wholesale power market prices can impact these mitigation efforts.

Unregulated Business: Catamount has sufficient cash flow to cover its ongoing operating expenses, but additional project investments that will allow Catamount to execute its growth strategy will require third party financing, as discussed above, and an equity investor.

Catamount has solicited offers from selected financial institutions for a credit facility to be secured by its Sweetwater equity investments. Catamount expects to close on a facility in the second quarter of 2005 and expects to use the proceeds to payoff the $12.8 million bridge loan extended by the Company to Catamount in April 2005 as discussed above. While Catamount expects to close on a credit facility in the second quarter of 2005, there can be no assurance that Catamount will be successful in securing a credit facility in the desired timeframe. In addition, Catamount is seeking capital from an equity investor or partner in 2005, and a portion of those proceeds could be used to fully repay the bridge loan.

DISCONTINUED OPERATIONS

On January 1, 2004, Connecticut Valley completed the sale of substantially all of its plant assets and its franchise to PSNH. The sale, including termination of the power contract between us and Connecticut Valley, resolved all Connecticut Valley restructuring litigation in New Hampshire and our stranded cost litigation at FERC.

For accounting purposes, components of the sale transaction are recorded in both continuing and discontinued operations in the 2004 Condensed Consolidated Statement of Income. First quarter 2004, income from discontinued operations included a gain on disposal of about $21 million pre-tax, or $12.3 million after-tax. In addition to the gain on disposal, we recorded a loss on power costs of $8.4 million pre-tax relating to termination of the power contract with Connecticut Valley. The loss is included in Purchased Power on the Condensed Consolidated Statement of Income. When the two accounting transactions are combined to assess the total impact of the sale, the result is a gain of $3.9 million recorded in the first quarter of 2004.

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There are no remaining significant business activities related to Connecticut Valley. Summarized results of operations of the discontinued operations are as follows (in thousands):

	March 31	March 31
	2005	2004
Operating revenues	$-	$-
Operating expenses
Purchased power	-	-
Other operating expenses	-	243
Income tax benefit	-	(85)
Total operating expenses	-	158
Operating loss	-	(158)
Other income, net	-	28
Net loss, net of tax	-	(130)
Gain from disposal, net of $8,729 tax	-	12,386
Income from discontinued operations, net of tax	$-	$12,256

ENERGY INITIATIVES IN VERMONT

The State of Vermont continues to examine changes to the provision of electric service absent introduction of retail choice. The following discussion provides an update on initiatives of potential significance.

Renewable Portfolio Standard In 2005 several bills were introduced in the Vermont General Assembly to establish a Renewable Portfolio Standard ("RPS") requirement. A specific legislative proposal under consideration and that we expect to pass would require by January 2012 that, in aggregate, Vermont utilities have new renewable energy supplies or Renewable Energy Certificates equal to the state's total incremental load growth between 2005 and 2012, up to a cap of 10 percent of 2005 electricity sales. If the PSB determines this requirement has been met, no other action would be necessary. If the PSB determines this requirement has not been met, a utility-specific RPS would be imposed that could require that we purchase certain amounts of our energy supply requirement from new renewable sources while maintaining existing renewable power content.

Alternative Forms of Regulation In 2003, the Vermont General Assembly authorized alternative forms of regulation for electric utilities that, besides other criteria, establish a reasonably balanced system of risks and rewards to encourage utilities to operate as efficiently as possible. Only an electric utility may initiate an alternative regulation plan proposal. The PSB may only approve an alternative regulation plan if it finds that the plan will not adversely affect our eligibility for rate-regulated accounting in accordance with GAAP and reasonably preserves the availability of equity and debt capital resources to us on favorable terms and conditions. To date, we have not sought authorization to implement an alternate form of regulation. However, the 2005 Vermont Legislature is considering legislation that we believe is likely to pass that would allow the PSB to initiate an alternative regulation plan proposal without our agreement.

RECENT ACCOUNTING PRONOUNCEMENTS

See Note 1 to the accompanying Condensed Consolidated Financial Statements.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

We consider our most significant risks to be 1) regulatory risk as it relates to timely and full recovery of costs to serve our customers, and 2) wholesale power market risks given that we rely on two long-term contracts that support about 75 percent of our load requirements. Except as discussed below there were no material changes from the disclosures in our Annual Report on Form 10-K for the year ended December 31, 2004.

Regulatory The Company currently complies with the provisions of SFAS No. 71 Accounting for the Effects of Certain Types of Regulation,("SFAS No. 71") for its regulated Vermont service territory and FERC-regulated wholesale businesses.  If we determine the Company no longer meets the criteria under SFAS No. 71, the accounting impact would be an extraordinary charge to operations of about $26.3 million on a pre-tax basis as of March 31, 2005, assuming no stranded cost recovery would be allowed through a rate mechanism.

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Wholesale Power Market Risk Summarized information related to the fair value of energy-related derivatives is shown in the table below (in thousands):

	Forward Sale Contract	Hydro-Quebec Sellback #3
Fair value at January 1, 2005 - unrealized gain (loss)	$385	$(5,735)
Change in fair value	(4,861)	257
Fair value at March 31, 2005 - unrealized gain (loss)	$(4,476)	$(5,478)
Source	Over-the-counter-quotations	Quoted market data & valuation methodologies

Changes in fair value of these derivatives are recorded as deferred charges or deferred credits on the Condensed Consolidated Balance Sheets depending on whether the fair value is an unrealized loss or gain, with an offsetting amount recorded as a decrease or increase in the related derivative asset or liability. See Item 2, Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with participation from the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the "Exchange Act")), as of the end of the period covered by this interim report on Form 10-Q. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of March 31, 2005, our disclosure controls and procedures were effective in timely alerting them to internal information related to the Company (including its consolidated subsidiaries) required to be included in reports filed or submitted by the Company to the Securities and Exchange Commission.

Changes in Internal Control over Financial Reporting

There was no change in our internal control over financial reporting that occurred during the first quarter of 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION
Item 1.		Legal Proceedings.
	The Company is involved in legal and administrative proceedings in the normal course of business and does not currently believe that the ultimate outcome of these proceedings will have a material adverse effect on the financial position or the results of operations of the Company, except as otherwise disclosed herein
Item 4.		Submission of Matters to a Vote of Security Holders.
		(a)   The Registrant held its Annual Meeting of Stockholders on May 3, 2005.
		(b)   Directors elected whose term will expire in year 2008:
						Votes FOR	Votes WITHHELD
		Rhonda L. Brooks         Janice B. Case         George MacKenzie, Jr.         Robert H. Young				10,436,022 10,494,039 10,493,695 10,290,282	155,924   97,906   98,250 301,664
		Other Directors whose terms will expire in 2006:
		Robert L. Barnett         Frederic H. Bertrand         Robert G. Clarke         Mary Alice McKenzie
		Other Directors whose terms will expire in 2007:
		Timothy S. Cobb         Bruce M. Lisman         Janice L. Scites
		(c)   Ratification of the appointment of Deloitte & Touche LLP as independent registered public accountants         for fiscal year ending December 31, 2005.
		For         Against         Abstain			10,433,830      102,452        55,662
Item 6.		Exhibits.
		(a)	List of Exhibits
			31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
			31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
			32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
			32.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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SIGNATURE       Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
	CENTRAL VERMONT PUBLIC SERVICE CORPORATION
	(Registrant)
By	/s/ Jean H. Gibson
	Jean H. Gibson Senior Vice President, Principal Financial Officer, and Treasurer

Dated  May 10, 2005

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EXHIBIT INDEX
Exhibit Number	Exhibit Description
31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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EX-31

EXHIBIT 31.1 ANNUAL CERTIFICATION OF CHIEF EXECUTIVE OFFICER REQUIRED BY SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Robert H. Young, certify that:
1.	I have reviewed this quarterly report on Form 10-Q of Central Vermont Public Service Corporation (the "Registrant");
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;
4.	The Registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have:
	a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c)	Evaluated the effectiveness of the Registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d)	Disclosed in this report any change in the Registrant's internal control over financial reporting that occurred during the Registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant's internal control over financial reporting; and
5.	The Registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant's auditors and the audit committee of the Registrant's board of directors:
	a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant's ability to record, process, summarize and report financial information; and
	b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant's internal control over financial reporting.
Date: May 10, 2005 /s/ Robert H. Young Robert H. Young Chief Executive Officer

EX-31

EXHIBIT 31.2 ANNUAL CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER REQUIRED BY SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Jean H. Gibson, certify that:
1.	I have reviewed this quarterly report on Form 10-Q of Central Vermont Public Service Corporation (the "Registrant");
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;
4.	The Registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have:
	a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c)	Evaluated the effectiveness of the Registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d)	Disclosed in this report any change in the Registrant's internal control over financial reporting that occurred during the Registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant's internal control over financial reporting; and
5.	The Registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant's auditors and the audit committee of the Registrant's board of directors:
	a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant's ability to record, process, summarize and report financial information; and
	b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant's internal control over financial reporting.
Date: May 10, 2005 /s/ Jean H. Gibson Jean H. Gibson Chief Financial Officer

EX-32

EXHIBIT 32.1

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

            In connection with the Quarterly Report of Central Vermont Public Service Corporation (the "Company") on Form 10-Q for the period ending March 31, 2005 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I Robert H. Young, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge and belief:

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

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

/s/ Robert H. Young

Robert H. Young
Chief Executive Officer
May 10, 2005

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

EX-32

EXHIBIT 32.2

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

            In connection with the Quarterly Report of Central Vermont Public Service Corporation (the "Company") on Form 10-Q for the period ending March 31, 2005 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I Jean H. Gibson, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge and belief:

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

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

/s/ Jean H. Gibson

Jean H. Gibson
Chief Financial Officer
May 10, 2005

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