CENTRAL VERMONT PUBLIC SERVICE CORPORATION

-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Wz77K2wrR0USS3D113WdDxPxF+S9tLqbn8uFhTHcy9/dPUdD7/iPqM/UO190J6eA Rz97ADnokw2sQXkepSNKUA== 0000018808-06-000069.txt : 20060510 0000018808-06-000069.hdr.sgml : 20060510 20060510083614 ACCESSION NUMBER: 0000018808-06-000069 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20060331 FILED AS OF DATE: 20060510 DATE AS OF CHANGE: 20060510 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CENTRAL VERMONT PUBLIC SERVICE CORP CENTRAL INDEX KEY: 0000018808 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 030111290 STATE OF INCORPORATION: VT FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-08222 FILM NUMBER: 06823422 BUSINESS ADDRESS: STREET 1: 77 GROVE ST CITY: RUTLAND STATE: VT ZIP: 05701 BUSINESS PHONE: 802-773-2711 MAIL ADDRESS: STREET 1: 77 GROVE STREET CITY: RUTLAND STATE: VT ZIP: 05701 10-Q 1 fnl10q.htm FORM 10-Q QUARTERLY PERIOD ENDED MARCH 31, 2006 CENTRAL VERMONT PUBLIC SERVICE CORPORATION 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, 2006

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

For the transition period from _______ to _______

Commission file number 1-8222

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

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

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

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

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

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes [ ] No [X]

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. As of April 28, 2006 there were outstanding 10,074,697 shares of Common Stock, $6 Par Value.

Cover Page

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Form 10-Q - 2006

Table of Contents

		Page
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Statements of Income (Loss) (unaudited) for the three months ended March 31, 2006 and 2005	3
	Condensed Consolidated Statements of Comprehensive Income (Loss) (unaudited) for the three months ended March 31, 2006 and 2005	4
	Condensed Consolidated Statements of Cash Flows (unaudited) for the three months ended March 31, 2006 and 2005	5
	Condensed Consolidated Balance Sheets as of March 31, 2006 (unaudited) and December 31, 2005	6
	Condensed Consolidated Statements of Retained Earnings (unaudited) for the three months ended March 31, 2006 and 2005	8
	Notes to Condensed Consolidated Financial Statements	9
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	39
Item 4.	Controls and Procedures	40
PART II	OTHER INFORMATION	41
SIGNATURES		43
EXHIBIT INDEX		44

Page 2 of 44

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS) (in thousands, except share data) (unaudited)
	Three months ended March 31,
	2006	2005
Operating Revenues	$82,255	$75,664
Operating Expenses Operation Purchased Power - affiliates Purchased Power - other sources Production Transmission - affiliates Transmission - other Other Operation Maintenance Depreciation Other taxes, principally property Income tax expense (benefit) Total Operating Expenses	16,810 25,678 2,853 1,343 3,452 12,563 5,515 4,091 3,616 1,714 77,635	15,989 25,858 2,771 914 3,509 22,553 3,606 4,065 3,606 (6,219) 76,652
Operating Income (Loss)	4,620	(988)
Other Income and (Deductions) Equity in earnings of affiliates Allowance for equity funds during construction Other income Other deductions (Provision) benefit for income taxes Total Other Income and (Deductions)	517 23 2,153 (721) (453) 1,519	483 13 475 (1,685) 44 (670)
Total Operating and Other Income (Deductions)	6,139	(1,658)
Interest Expense Interest on long-term debt Other interest Allowance for borrowed funds during construction Total Interest Expense	1,799 251 (8) 2,042	1,799 1,462 (4) 3,257
Income (loss) from continuing operations Income from discontinued operations, net of income tax Net Income (Loss) Dividends declared on preferred stock	4,097 - 4,097 92	(4,915) 288 (4,627) 92
Earnings (loss) available for common stock	$4,005	$(4,719)
Per Common Share Data: Basic: Earnings (loss) from continuing operations Earnings from discontinued operations Earnings (loss) per share Diluted: Earnings (loss) from continuing operations Earnings from discontinued operations Earnings (loss) per share	$0.33 - $0.33 $0.32 - $0.32	$(.41) 0.02 $(.39) $(.41) 0.02 $(.39)
Average shares of common stock outstanding - basic Average shares of common stock outstanding - diluted Dividends declared per share of common stock	12,297,528 12,363,931 $-	12,219,130 12,219,130 $.46

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

Page 3 of 44

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (in thousands) (unaudited)
	Three months ended March 31,
	2006	2005
Net Income (loss)	$4,097	$(4,627)
Other comprehensive income (loss), net of tax: Investments: Unrealized holding (loss) gain net of income taxes of $22 in 2006 and $(47) in 2005 Realized (gain) loss net of income taxes of $(17) in 2006 and $114 in 2005 Foreign currency Other comprehensive income from discontinued operations, net of income taxes of $0 in 2006 and $7 in 2005	33 (25) - 8	(69) 166 10 107
Comprehensive Income (loss)	$4,105	$(4,520)

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

Page 4 of 44

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)
	Three months ended March 31,
	2006	2005
Cash flows provided (used) by: OPERATING ACTIVITIES Net income Deduct: Income from discontinued operations, net of income taxes Income (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 Depreciation Amortization, net Deferred income taxes and investment tax credits Charge related to Rate Order Losses and amortization of premiums on available-for-sale securities Non-utility depreciation and other Gain on sales of property Changes in assets and liabilities: Decrease in accounts receivable and unbilled revenues Decrease in accounts payable Increase in accrued income taxes Increase in other current assets Decrease in special deposits Decrease in other current liabilities Pension and postretirement trust fund contributions Other non-current assets and liabilities and other Net cash provided by operating activities of continuing operations	$4,097 - 4,097 (517) 358 4,091 (272) 101 - - (63) 179 (318) 1,866 (2,147) 2,034 (346) 11,938 (549) (16,308) 2,068 6,212	$(4,627) 288 (4,915) (483) 553 4,065 375 (9,025) 21,772 645 (512) - - 387 (4,668) 3,708 (716) - - (1,956) - - 3,403 12,633
INVESTING ACTIVITIES Construction and plant expenditures Investments in available-for-sale securities Proceeds from sale of available-for-sale securities Investment in discontinued operations Note receivable repayment - discontinued operations Catamount sale costs (previously accrued) Increase in restricted cash Proceeds from sales of property Return of capital from investments in affiliates Other investments Net cash provided by (used for) investing activities of continuing operations	(4,950) (222,005) 235,410 - - - - (309) (41) 334 120 (168) 8,391	(3,407) (64,300) 61,200 (5,000) 11,000 - - - - - - 35 106 (366)
FINANCING ACTIVITIES Proceeds from issuance of common stock Common and preferred dividends paid Proceeds from borrowings under revolving credit facility Repayments under revolving credit facility Reduction in capital lease obligations Stock reacquisition costs - tender offer and other Net cash used for financing activities of continuing operations	242 (3,003) 300 (300) (255) (286) (3,302)	419 (3,025) - - - - (253) (3) (2,862)
DISCONTINUED OPERATIONS Net cash provided by operating activities Net cash provided by investing activities Net cash used for financing activities Net cash provided by discontinued operations	- - - - - -	4,942 2,583 (6,000) 1,525
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	11,301 6,576 $17,877	10,930 11,722* $22,652*

*Assets of discontinued operations included cash of $4.0 million at March 31, 2005 and $2.5 million at December 31, 2004.

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

Page 5 of 44

CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands, except share data)
	(unaudited) March 31, December 31, 2006 2005
ASSETS Utility plant, at original cost Less accumulated depreciation Net utility plant Construction work-in-progress Nuclear fuel, net Total utility plant	$516,646 225,316 291,330 8,080 1,089 300,499	$513,590 222,167 291,423 8,588 1,222 301,233
Investments and other assets Investment in affiliates Non-utility property, less accumulated depreciation ($4,060 in 2006 and $4,063 in 2005) Millstone decommissioning trust fund Available-for-sale securities Other Total investments and other assets	15,776 2,007 4,995 3,918 6,583 33,279	15,801 2,033 4,885 5,450 6,411 34,580
Current assets Cash and cash equivalents Available-for-sale securities Restricted cash Special deposits Accounts receivable, less allowance for uncollectible accounts ($2,912 in 2006 and $2,614 in 2005) Accounts receivable - affiliates, less allowance for uncollectible accounts ($48 in 2006 and 2005) Unbilled revenues Materials and supplies, at average cost Prepayments Deferred income taxes Other current assets Total current assets	17,877 60,567 925 7,155 22,200 184 15,467 4,350 8,348 3,336 894 141,303	6,576 72,432 883 21,094 22,682 71 16,900 4,339 8,048 3,199 859 157,083
Deferred charges and other assets Regulatory assets Other deferred charges - regulatory Other Total deferred charges and other assets TOTAL ASSETS	27,660 16,665 7,105 51,430 $526,511	30,444 21,045 7,048 58,537 $551,433
The accompanying notes are an integral part of these condensed consolidated financial statements. Page 6 of 44
CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands, except share data)
	(unaudited) March 31, December 31, 2006 2005
CAPITALIZATION AND LIABILITIES Capitalization Common stock, $6 par value, authorized 19,000,000 shares (issued and outstanding 12,301,915 and 12,283,405 shares at March 31, 2006 and December 31, 2005, respectively) 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	$73,779 52,771 (406) - - 95,582 221,726 8,054 3,000 115,950 5,979 354,709		$73,695 52,513 (414) (5) 91,581 217,370 8,054 4,000 115,950 6,153 351,527
Current liabilities Current portion of preferred stock Accounts payable Accounts payable - affiliates Notes payable Accrued income taxes Accrued interest Dividends declared Nuclear decommissioning costs Power contract derivatives Other current liabilities Total current liabilities	1,000 4,135 11,235 10,800 2,804 2,099 - - 5,032 3,000 17,183 57,288		2,000 7,066 11,402 10,800 769 344 2,825 5,677 4,498 20,248 65,629
Deferred credits and other liabilities Deferred income taxes Deferred investment tax credits Nuclear decommissioning costs Asset retirement obligations Accrued pension and benefit obligations Power contract derivatives Other deferred credits - regulatory Other Total deferred credits and other liabilities Commitments and contingencies TOTAL CAPITALIZATION AND LIABILITIES	28,960 4,004 13,735 3,926 11,080 10,315 14,377 28,117 114,514 $526,511		28,647 4,099 14,670 4,059 25,436 13,414 15,424 28,528 134,277 $551,433
.

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

Page 7 of 44

CONDENSED CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (in thousands) (unaudited)
	Three months ended March 31, 2006 2005
Retained earnings at beginning of period Net income (loss) from continuing operations Net income from discontinued operations Retained earnings before dividends	$91,581 4,097 - 95,678	$99,702 (4,915) 288 95,075

Cash dividend declared Preferred stock Common stock Total dividends declared Retained earnings at end of period	92 4 96 $95,582	92 5,621 5,713 $89,362

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

Page 8 of 44

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - 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. The Company's non-regulated wholly owned subsidiary Catamount Resources Corporation ("CRC") owns Eversant Corporation ("Eversant"), which operates a rental water heater business through its wholly owned subsidiary, SmartEnergy Water Heating Services, Inc. Other wholly owned subsidiaries include Custom Investment Corporation ("Custom") a passive investment subsidiary that holds the Company's investment in Vermont Yankee Nuclear Power Corporation ("VYNPC"), and Connecticut Valley Electric Company ("Connecticut Valley"), which completed the sale of substantially all of its plant assets and franchise on January 1, 2004.

In the fourth quarter of 2005, CRC decided to sell all of its interest in Catamount Energy Corporation ("Catamount"), which had primarily invested in wind energy projects in the United States and the United Kingdom. The sale to CEC Wind Acquisition, LLC, a Delaware limited liability company established by Diamond Castle Holdings ("Diamond Castle"), was consummated on December 20, 2005.

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. The Company will record reclassifications to prior year financial statements when considered necessary or to conform to current-year presentation. Operating results for the first quarter of 2006 are not necessarily indicative of the results that may be expected for the 12-months ended December 31, 2006. For further information, refer to the consolidated financial statements and footnot es thereto included in the Company's annual report on Form 10-K for the year ended December 31, 2005 and other SEC filings.

The condensed consolidated financial statements present Catamount as discontinued operations, in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS No. 144"). The Company began reporting Catamount as discontinued operations in the fourth quarter of 2005. See Note 4 - Discontinued Operations.

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.

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 $29.9 million pre-tax as of March 31, 2006. The Company would also be required to determine any impairment to the carrying costs of deregulated plant. See Note 3 - Retail Rates and Regulatory Accounting.

Page 9 of 44

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

	March 31, 2006	December 31, 2005
Deferred compensation plans Accrued employee costs - payroll and medical Other taxes and Energy Efficiency Utility Cash concentration account - outstanding checks Miscellaneous reserves - environmental, accident and other Reserve for loss on power contract Customer deposits, prepayments and interest Obligation under capital leases Miscellaneous accruals Total	$2,568 2,779 3,175 1,460 1,486 1,196 1,181 860 2,478 $17,183	$2,569 3,253 3,016 3,021 1,257 1,196 1,167 941 3,828 $20,248

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

	March 31, 2006	December 31, 2005
Environmental Reserve Non-legal removal costs Contribution in aid of construction - tax adder Reserve for loss on power contract Other Total	$4,798 7,852 4,761 10,464 242 $28,117		$5,016 7,627 4,881 10,763 241 $28,528

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

Three months ended March 31, 2006                2005

Interest on temporary investments
Non-utility revenue and non-operating rental income
Amortization of contributions in aid of construction
Other interest and dividends
Regulatory asset carrying costs*
Miscellaneous other income
Total

$890
473
218
159
- -
      413
$2,153

$340
483
210
91
(653)
      4
$475

*For 2005, includes $(822) of Rate Order-related adjustments.

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

Three months ended
March 31, 2006                2005

Supplemental retirement benefits and insurance
Non-utility expenses
Realized losses on available-for-sale securities
Vermont Yankee fuel rod disallowance - Rate Order
Miscellaneous other deductions
Total

$161
324
- -
- -
  236
$721

$252
277
573
403
     180
$1,685

Page 10 of 44

Accumulated Other Comprehensive Income (Loss) The accumulated balance for each other comprehensive income (loss) item, net of income taxes, is as follows (in thousands):

	December 31, 2005	Change	March 31, 2006
Unrealized loss on investments Non-qualified benefit obligations Accumulated other comprehensive income (loss)	$(20) (394) $(414)	$8 - $8	$(12) (394) $(406)

Stock-Based Compensation Effective January 1, 2006, the Company adopted SFAS No. 123R, Share-Based Payment, ("SFAS No. 123R") which amends SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees ("APB 25"), and related Interpretations. The Company adopted the provisions of SFAS No. 123R using the modified prospective method, therefore prior periods have not been restated to reflect the impact of SFAS No. 123R. In accordance with SFAS No. 123R compensation costs relating to share-based payments are to be recognized in the financial statements. That cost is measured on the fair value of the equity or liability instruments issued. SFAS No. 123R also requires the benefits of tax deductions in excess of recognized compensation expense be reported as financing cash flows, rather than as operating cash flows as prescribed under prior accounting guidance. This requirement reduces net operating cash flows and increases net financing cash flows in periods after adoption, but total cash flow remains unchanged.

Prior to adoption of SFAS No. 123R, the Company followed the guidance of APB No. 25 in accounting for its stock-based compensation plans. Accordingly no compensation expense was recognized for stock option grants for periods prior to January 1, 2006. The Company will continue to provide pro forma disclosure amounts in accordance with SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of SFAS No. 123 to illustrate the effect on net income and earnings per share as if the fair value method had been applied to all stock-based compensation in the reporting period. Since the Company did not grant stock options during the first quarter of 2005, there was no difference in net income or per share amounts for disclosure purposes.

The adoption of SFAS No. 123R primarily resulted in a change in the Company's method of recognizing fair value of share-based compensation, and did not have a material affect on the Company's financial position or results of operations. In the first quarter of 2006, the Company recorded total share-based compensation expense of about $0.1 million related to restricted-stock and performance shares. In the first quarter of 2005, the Company reversed previously recorded compensation expense of about $0.1 million because targeted financial goals were not achieved under the performance share plan. The Company's share-based compensation plans are described in more detail in Note 6 - Share-Based Compensation.

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

Three months ended March 31,
    2006                      2005

Numerator for basic and diluted EPS:

Net income (loss) from continuing operations:
   Income (loss) from continuing operations
   Dividends declared on preferred stock
   Net income (loss) from continuing operations available for common stock

Denominators for basic and diluted EPS:
Average shares of common stock outstanding - basic
   Dilutive effect of stock options
   Dilutive effect of unvested and performance shares
Average shares of common stock outstanding - diluted

$4,097
     (92)
$4,005

12,297,528
63,673
        2,730
12,363,931

$(4,915)
       (92)
$(5,007)

12,219,130
- -
                -
12,219,130

Page 11 of 44

At March 31, 2006, 67,577 shares of outstanding stock options were excluded from the computation of diluted shares because the exercise prices were above the average market price of the common shares. At March 31, 2005, the exercise prices for all outstanding shares were lower than the average market price. Since the Company incurred a loss in the first quarter of 2005, potentially dilutive common shares (162,891 shares of outstanding stock options and 5,892 shares of restricted stock) were excluded from the calculation of diluted EPS.

On April 19, 2006, the Company purchased 2,249,975 shares of common stock through a tender offer that expired on April 5, 2006. The effect of the stock buyback is not reflected in the average common stock outstanding shown in the table above. See Note 10 - Subsequent Events.

Cash and Cash Equivalents The Company considers all liquid investments with an original maturity of three months or less when acquired to be cash and cash equivalents.

Special Deposits At March 31, 2006, the Company had special deposits of $7.2 million relating to collateral payments. At December 31, 2005, the Company had special deposits of $21.1 million including $19.1 million for collateral payments and $2.0 million for mandatory redeemable preferred stock. The $2.0 million payment to preferred shareholders was made effective January 1, 2006 which included $1.0 million for a mandatory sinking fund payment and $1.0 million for an optional sinking fund payment. The collateral payments relate to performance assurance requirements for certain of the Company's power contracts, as described in Note 8 - Commitments and Contingencies - Performance Assurance.

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

Three months ended March 31,
2006                 2005

Cash paid during the year for:
   Interest (net of amounts capitalized)
   Income taxes (net of refunds)

$173
$25

$89
$34

Auction rate securities Investments in auction rate securities and proceeds from sale of auction rate securities are included in Investing Activities on the Condensed Consolidated Statements of Cash Flows.

Non-cash Operating, Investing and Financing Activities For additional information relating to non-cash activities see Note 3 - Retail Rates and Regulatory Accounting and Note 8 - Commitments and Contingencies.

Cash Concentration Account The Company maintains a cash concentration account for payments related to its routine business activities. At the end of each reporting period, the Company records the amount of outstanding checks as a current liability, which represents a book overdraft position with a positive bank account balance.

Recent Accounting Pronouncements
SFAS No. 123R: See Stock-Based Compensation above.

FSP No. FIN 46(R)-6: In April 2006, FASB issued Staff Position No. FIN 46(R)-6, Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R) ("FSP No. 46(R)-6"). This pronouncement provides guidance on how a reporting enterprise should determine the variability to be considered in applying FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, which could impact the assessment of whether certain variable interest entities are consolidated. FSP No. 46(R)-6 is effective on July 1, 2006 and is to be applied prospectively. The impact, if any, is dependent on transactions that could occur subsequent to the effective date, and therefore cannot be determined until the transaction occurs.

Page 12 of 44

NOTE 2 - INVESTMENTS IN AFFILIATES
Vermont Yankee Nuclear Power Corporation ("VYNPC") Summarized financial information follows (in thousands):

Three months ended March 31,
2006 2005

Operating revenues
Operating income
Net income

Company's ownership interest: 58.85%
Company's equity in net income

$44,347
$776
$173

$102

$42,349
$56
$162

$95

The Company received $0.1 million of cash dividends from VYNPC in the first quarters of 2006 and 2005. VYNPC's revenues shown in the table above include sales to the Company of $15.4 million in 2006 and $14.7 million in 2005. These amounts are included in Purchased power - affiliates on the Company's Condensed Consolidated Statements of Income. Accounts payable to VYNPC amounted to $5.3 million at March 31, 2006 and $5.4 million at December 31, 2005.

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

Three months ended March 31,
   2006                2005

Operating revenues
Operating income
Net income

Company's ownership interest:
   Common stock
    Preferred stock

Company's equity in net income

$8,987
$2,214
$771

47.05%
48.03%

$391

$7,982
$2,091
$730

47.02%
48.03%

$365

The Company received about $0.4 million of cash dividends from VELCO in the first quarter of 2006, which included less than $0.1 million related to return of capital from VELCO's Class C preferred stock. In the first quarter of 2005, the Company received about $0.4 million in cash dividends from VELCO. Of that amount, less than $0.1 million was related to return of capital from VELCO's Class C preferred stock.

Included in VELCO's revenues above are billings to the Company of $1.3 million in 2006 and $0.9 million in 2005. These amounts are reflected in Transmission - affiliates on the Company's Condensed Consolidated Statements of Income. Other transmission-related billings to the Company from VELCO that are not included in VELCO's revenues are included in Transmission - others. Accounts payable to VELCO amounted to $5.6 million at March 31, 2006 and $5.9 million at December 31, 2005.

Maine Yankee, Connecticut Yankee and Yankee Atomic
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. Total billings from the three companies amounted to $1.4 million for the three months ended March 31, 2006 and $1.2 million for the same period in 2005. These amounts are included in Purchased power - affiliates on the Company's Condensed Consolidated Statements of Income. The Company's obligations related to these plants are described in Note 8 - Commitments and Contingencies.

Page 13 of 44

NOTE 3 - RETAIL RATES AND REGULATORY ACCOUNTING
Retail Rates The Company recognizes adequate and timely rate relief is required to maintain its financial strength, particularly since Vermont law does not allow purchased power and fuel costs to be passed on to consumers through purchased power and fuel adjustment clauses. The Company will continue to review costs and request rate increases when warranted.

The Company's current retail rates are based on a March 29, 2005 PSB Order ("Rate Order") that when finalized included, among other things: 1) a 2.75 percent rate reduction beginning April 1, 2005; 2) a $6.5 million pre-tax refund to customers, 3) a 10 percent return on equity (reduced from 11 percent); and 4) a requirement that the gain resulting from termination of the power contract related to the 2004 Connecticut Valley sale be applied to the benefit of ratepayers to compensate for increased costs.

The Rate Order resulted in a $21.8 million pre-tax charge to utility earnings in the first quarter of 2005. The primary components of the charge to earnings included: 1) a revised calculation of overearnings for the period 2001 - 2003; 2) application of the gain resulting from termination of the power contract with Connecticut Valley to reduce costs; 3) a customer refund for the period April 7, 2004 through March 31, 2005; and 4) amortization of costs and other adjustments.

On June 22, 2005, the Company filed an appeal of portions of the Rate Order with the Vermont Supreme Court. On July 11, 2005, the Company filed a docketing statement with the court in which it outlined the issues in its case. The docketing statement describes the ordered payback of earnings from periods prior to the opening of the rate investigation, namely the years 2001 to 2003 and also the first quarter of 2004, when the Company recorded a gain from the Connecticut Valley sale. The issues that were raised on appeal primarily focus on whether the Rate Order set rates retroactively without statutory authorization. On July 27, 2005, the DPS filed a response opposing the Company's position. The Company filed its legal brief and other materials in the case on August 22, 2005. Expedited oral argument occurred on January 31, 2006. The Company expects a Vermont Supreme Court decision on the case in the second or third quarter of 2006. The Company is not able to predict the outcome of this matter at this t ime.

Regulatory Accounting Under SFAS No. 71, the Company accounts for certain transactions in accordance with permitted regulatory treatment such that regulators may permit incurred costs, typically treated as expenses by unregulated entities, to be deferred and expensed in future periods when recovered in future revenues. Regulatory assets and certain other deferred credits are being amortized in accordance with the Rate Order. In the Rate Order, the PSB ordered that when a regulatory asset or liability is fully amortized, the corresponding rate revenue shall be booked as a reverse amortization in an opposing regulatory liability or asset account. These items, including other deferred credits, are also adjusted upward or downward in accordance with permitted regulatory treatment. The table below provides a summary of net regulatory assets, deferred charges and deferred credits.

	(in thousands)
	March 31, December 31, 2006 2005
Regulatory assets* Nuclear plant dismantling costs Nuclear refueling outage costs - Millstone Income taxes Vermont Yankee sale costs (non-tax) Vermont Yankee fuel rod maintenance deferral Asset retirement obligations Other Subtotal Regulatory assets	$19,284 1,230 3,786 1,984 924 394 58 27,660	$20,995 1,538 3,810 2,481 1,154 384 82 30,444
Other deferred charges - regulatory Vermont Yankee sale costs (tax) Unrealized loss on power contract derivatives Other Subtotal Other deferred charges - regulatory	3,130 13,315 220 16,665	3,130 17,912 3 21,045
Page 14 of 44
Other deferred credits - regulatory Vermont utility overearnings 2001 - 2003 Connecticut Valley gain on termination of power contract Asset retirement obligation - Millstone Unit #3 Vermont Yankee IRS settlement Emission allowances and renewable energy credits Other Subtotal Other deferred credits - regulatory	7,685 2,216 1,586 1,088 549 1,253 14,377	8,646 2,770 1,337 1,088 481 1,102 15,424
Net regulatory assets, deferred charges and deferred credits	$29,948	$36,065
* Regulatory assets are being recovered in retail rates, except for the asset retirement obligations. All regulatory assets are earning a return, except for income taxes, asset retirement obligations, and nuclear dismantling costs that have not yet been incurred by the Company.

NOTE 4 - DISCONTINUED OPERATIONS

The sale of the Company's investment in Catamount to Diamond Castle was consummated on December 20, 2005. Cash proceeds from the sale amounted to $59.25 million, resulting in an after-tax gain of $5.6 million in 2005. Catamount's results of operations included in discontinued operations reflect the reallocation of certain corporate costs back to continuing operations since they were not eliminated by the sale. Reversal of these costs is reflected in Catamount's operating expenses, net of income tax, in the summary of Catamount's results of operations below (in thousands).

Three months ended March 31,
   2006                2005

Operating revenues
Operating expenses
   Operating Income

Other income and (deductions):
   Equity in earnings of non-utility investments
   Other income
   Other deductions
   Benefit for income taxes
Total other income and (deductions)

Total operating and other income
Total interest expense

Net income from discontinued operations

$-
  -
  -

- -
- -
- -
  -
  -

- -
  -

$-

$-
(99)
99

932
1,183
(1,814)
    (38)
   263

362
   74

$288

See Note 8 - Commitments and Contingencies for indemnifications related to Catamount.

NOTE 5 - INVESTMENT SECURITIES
Available-for-sale securities The Company evaluates the carrying value of the bond portfolio on a quarterly basis, or when events and circumstances warrant evaluation to determine whether a decline in fair value is considered temporary or other-than-temporary. Several criteria are considered 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 to retain investments in the issuer for a period of time sufficient to allow for any anticipated recovery in market value. There was no impairment in the first quarter of 2006 related to these investment securities. In the first quarter of 2005, the Company recorded a $0.3 million impairment.

In the first quarter of 2006, the Company recorded $0.1 million of realized gains on available-for-sale securities and minimal amortization of premiums. In the first quarter of 2005, the Company recorded $0.1 million of realized losses and $0.3 million of debt security premium amortizations to interest income as a deduction from the coupon interest earned on available-for-sale securities; these amounts were related to specific securities.

Page 15 of 44

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, based on forecasted cash needs. Therefore, such unrealized losses are considered temporary. Information regarding available-for-sale securities at March 31, 2006 follows (in thousands):

	March 31, 2006				December 31, 2005
Security Types	Amortized Cost	Fair Value	Unrealized Gains	Unrealized Losses	Amortized Cost	Fair Value	Unrealized Gains	Unrealized Losses
Current Assets: Debt Securities: US Government Obligations US Government Agencies Corporate Bonds Auction Rate Securities Subtotal Equity Securities: Auction Rate Securities Subtotal Investments and Other Assets: Debt Securities: US Government Obligations US Government Agencies Corporate Bonds Subtotal Total	- - $9,410 3,503 19,525 32,438 28,100 60,538 - - 3,972 - 3,972 $64,510	- - $9,440 3,502 19,525 32,467 28,100 60,567 - - 3,918 - 3,918 $64,485	- - $53 5 - 58 - 58 - - - - - - $58	- - $23 6 - 29 - 29 - - 54 - 54 $83	- - $12,355 4,732 27,100 44,187 28,200 72,387 - 3,973 1,504 5,477 $77,864	- - $12,390 4,742 27,100 44,232 28,200 72,432 - 3,943 1,507 5,450 $77,882	- - $82 29 - 111 - 111 - 1 3 4 $115	- - $47 19 - 66 - 66 - 31 - 31 $97

Information related to the fair value of debt securities at March 31, 2006 follows (in thousands):

Fair value of debt securities at contractual maturity dates

Debt Securities

Less than 1 year
$12,942

1 to 5 years
$3,918

5 to 10 years
-

After 10 years
$19,525

Total
$36,385

The following table presents the gross unrealized losses and fair value of certain 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):

	Debt Securities
	Fair Value	Unrealized Losses
Less than 12 months (2 securities) 12 months or more (2 securities) Total	$3,918 3,476 $7,394	$55 28 $83

Millstone Decommissioning Trust Fund The Company has decommissioning trust fund investments related to its joint-ownership interest in Millstone Unit #3. The unrealized losses on the decommissioning trust fund are minor when compared to their original cost; therefore, they are considered temporary. The fair value of these investments is summarized below (in thousands):

	March 31, 2006				December 31, 2005
Security Types	Amortized Cost	Fair Value	Unrealized Gains	Unrealized Losses	Amortized Cost	Fair Value	Unrealized Gains	Unrealized Losses
Equity Securities Debt Securities Cash and other Total	$2,423 1,317 18 $3,758	$3,656 1,321 18 $4,995	$1,243 18 - $1,261	$10 14 - $24	$2,415 1,283 42 $3,740	$3,551 1,292 42 $4,885	$1,151 22 - $1,173	$15 13 - $28

Page 16 of 44

Information related to the fair value of debt securities at March 31, 2006 follows (in thousands):

Fair value of debt securities at contractual maturity dates

Debt Securities

Less than 1 year
$31

1 to 5 years
$360

5 to 10 years
$242

After 10 years
$688

Total
$1,321

The following table presents the gross unrealized losses and fair value of certain investments, aggregated by investment category and the length of time these numerous securities have been in a continuous loss position, at March 31, 2006 (in thousands):

               Equity Securities

                    Debt Securities

Fair Value

Unrealized Losses

Fair Value

Unrealized Losses

Less than 12 months
12 months or more
     Total

$2
135
$137

-
$10
$10

$650
124
$774

$10
  4
$14

NOTE 6 - SHARE-BASED COMPENSATION

As described in Note 1 - Summary of Significant Accounting Policies, the Company adopted SFAS No. 123R on January 1, 2006. The adoption of SFAS No. 123R primarily resulted in a change in the Company's method of recognizing fair value of share-based compensation, and did not have a material effect on the Company's financial position or results of operations.

The Company's stock-based compensation to executive officers and non-employee directors has included a combination of stock options, restricted stock and performance shares. For purposes of the Company's stock-based compensation plans, restricted stock refers to shares of the Company's common stock that fully vest at date of grant or cliff vest upon completion of a predefined service condition (referred to as nonvested shares under SFAS No. 123R).

Stock options have been awarded to executive officers and non-employee directors under several stock option plans, including the 2002 Long-Term Incentive Plan ("2002 LTIP"), which also authorizes the granting of stock appreciation rights, restricted shares and performance shares. Restricted stock has been awarded to executive officers and non-employee directors under the 2002 LTIP and the 1997 Restricted Stock Plan. Performance shares have been awarded to executive officers under the 2002 LTIP. A total of 1,566,875 shares have been authorized under all of the Company's stock-based compensation plans, and as of March 31, 2006, 103,790 shares are available for future grants. The 2002 LTIP is the only plan that shares are available for future grants. To date, the Company has not granted stock appreciation rights as a form of compensation.

The Company typically settles stock options, restricted stock and performance share awards from authorized but un-issued common shares. Under the existing compensation plans, they may also be settled by issuance of treasury shares or through open market purchase of common shares. Performance share awards can also be settled in cash at the discretion of the Compensation Committee of the Company's Board of Directors. Historically, settlement of such awards has been made in the form of shares of common stock.

Page 17 of 44

Stock Options All outstanding stock options were granted at the fair market value of the common shares on the date of grant, and vested immediately. The maximum term of options is five years for non-employee directors and 10 years for executive officers. Effective January 1, 2006 future stock option grants were eliminated as a form of compensation to executive officers and non-employee directors. During the three months ended March 31, 2006, stock option activity was as follows:

	Options	Weighted Average Exercise Price	Weighted Average Contractual Life	Aggregate Intrinsic Value (in thousands)
Options outstanding and exercisable at January 1 Exercised Granted Forfeited or expired Options outstanding and exercisable at March 31	652,321 (14,010) - - (25,504) 612,807	$17.02 $17.29 - - $20.16 $16.89	5.3 5.0	$16 $2,545

Cash received from stock option exercises was about $0.2 million in the first quarter of 2006 and zero in the first quarter of 2005 since no stock options were exercised during that period. The actual tax benefit realized for the tax deductions from option exercises in the first quarter of 2006 was nominal. Adoption of SFAS No. 123R did not impact 2006 consolidated results related to stock options since all outstanding options were fully vested at December 31, 2005, and no stock options have been subsequently granted.

Nonvested Shares Under the 2002 LTIP, common stock can be granted to executive officers, key employees and non-employee directors. The shares typically cliff vests over service periods ranging from immediate to three years. Although full ownership of the shares does not transfer to the recipients until vested, the recipients have the right to vote the shares and to receive dividends from the date of grant. During the three months ended March 31, 2006, nonvested share activity was as follows:

	Restricted Stock	Weighted Average Grant-Date Fair Value
Nonvested at January 1 Granted Vested Forfeited Nonvested at March 31	892 4,500 - - - 5,392	$22.41 $21.65 - - - - $21.78

For the first quarters of 2006 and 2005, the Company recorded compensation expense of less than $0.1 million related to nonvested shares. Unearned compensation expense at March 31, 2006 is of a nominal amount.

Performance Shares The executive officer long-term incentive program is delivered in the form of contingent performance shares of common stock, and prior to January 1, 2006 also included a stock option component. At the start of each year a fixed number of contingent performance shares are granted for three-year service periods (referred to as performance cycles). The number of shares awarded at the end of each performance cycle is dependent on the Company's performance compared to pre-established performance targets for Total Shareholder Return ("TSR") and operational measures beginning with the 2005 performance cycle. The number of shares awarded at the end of the performance cycles ranges from 0 - 1.5 times the number of shares targeted, based on actual performance versus targets. Dividends payable with respect to performance shares are reinvested into additional performance shares. Once the award is earned, shares become fully vested. If the participant's employment is terminated mid-cycl e due to retirement, death, disability or a change-in-control, that employee is entitled to receive a pro rata portion of shares. During the three months ended March 31, 2006, performance share activity was as follows:

Page 18 of 44

	Performance Shares	Weighted Average Grant-Date Fair Value
Outstanding at January 1 (unvested) Granted (a) Vested Forfeiture Outstanding at March 31 (unvested)	5,320 38,455 - - - 43,775	$22.17 $18.49 - - - - $18.94
(a) Includes 4,655 shares for estimated dividends.

In the first quarter of 2006, the Company recorded compensation expense of about $0.1 million related to performance shares. No performance awards were made in the first quarter of 2006 since the Company did not meet the performance objectives for the 2003 - 2005 performance cycle. In the first quarter of 2005, the Company reversed previously recorded compensation expense of about $0.1 million because targeted financial goals were not expected to be achieved.

As of March 31, 2006, there was about $0.6 million of unrecognized compensation expense related to unvested performance shares. That cost is expected to be recognized over a weighted-average period of 2.3 years. Since compensation expense is based on awards ultimately expected to vest, it has been reduced for estimated forfeitures.

NOTE 7 - PENSION AND POSTRETIREMENT BENEFITS

At March 31, 2006, the fair value of Pension Plan trust assets was $78.6 million. At December 31, 2005, the fair value of Pension Plan trust assets was $66.4 million. In March 2006, the Company contributed an additional $12.2 million to the Pension Plan. At March 31, 2006, the accrued pension benefit obligation recognized in the Condensed Consolidated Balance Sheets was $4.8 million, compared to $15.7 million at December 31, 2005.

At March 31, 2006, the fair value of Postretirement Plan trust assets was $10.4 million. At December 31, 2005, the fair value of Postretirement Plan trust assets was $6.2 million. In March 2006, the Company contributed an additional $4.1 million to the Postretirement Plan. At March 31, 2006, the accrued postretirement benefit recognized in the Condensed Consolidated Balance Sheets was a prepayment of $0.3 million, compared to an accrued liability of $3.5 million at December 31, 2005.

Net Periodic Benefit Costs
Components of net periodic benefit costs for the three months ended March 31, 2006 and 2005 are as follows (in thousands):

	Pension Benefits		Postretirement Benefits
	2006	2005	2006	2005
Net benefit costs include the following components
Service cost	$922	$807	$177	$128
Interest cost	1,493	1,464	424	361
Expected return on plan assets	(1,436)	(1,317)	(179)	(119)
Amortization of prior service cost	100	100	-	-
Recognized net actuarial loss	196	49	398	278
Amortization of transition obligation	-	-	64	64
Net periodic benefit cost	1,275	1,103	884	712
Less amounts capitalized	204	167	142	108
Net benefit costs expensed	$1,071	$936	$742	$604

The Medicare Part D subsidy included in Postretirement net periodic benefit cost was about $0.1 million in each of the first quarters of 2006 and 2005 and is expected to be about $0.3 million for the year 2006.

Page 19 of 44

NOTE 8 - COMMITMENTS AND CONTINGENCIES
Maine Yankee, Connecticut Yankee and Yankee Atomic All three companies collect decommissioning and closure costs through FERC-approved wholesale rates charged under power agreements with several New England utilities, including the Company. Historically, the Company's share of these costs has been recovered from retail customers through PSB-approved rates. The Company believes its share of decommissioning and closure costs for each plant will continue to be recovered through the regulatory process, but there is a risk that FERC may not allow full recovery of Connecticut Yankee's increased costs in wholesale rates, as described below.

The Company's share of Maine Yankee, Connecticut Yankee and Yankee Atomic estimated costs are reflected on the Condensed Consolidated Balance Sheets as regulatory assets and nuclear decommissioning liabilities (current and non-current). These amounts are adjusted when revised estimates are provided by the companies. At March 31, 2006, the Company had regulatory assets of about $4.5 million related to Maine Yankee, $9.7 million related to Connecticut Yankee and $4.5 million related to Yankee Atomic (including about $0.5 million for incremental decommissioning costs already paid by the Company that are now being recovered in retail rates pursuant to the Rate Order). These estimated costs are being collected from customers through existing retail rate tariffs. Pursuant to the Rate Order, beginning April 1, 2006, the Company will defer any differences between actual decommissioning cost payments and amounts included for rate recovery, until its next rate proceeding.

Department of Energy ("DOE") Litigation: Maine Yankee, Connecticut Yankee and Yankee Atomic are seeking recovery of fuel storage-related costs stemming from the default of the DOE under the 1983 fuel disposal contracts that were mandated by the United States Congress under the Nuclear Waste Policy Act of 1982. Under the Act, the DOE was to begin removing spent nuclear fuel from the nuclear plants no later than January 1, 1998 in return for payments by each company into the nuclear waste fund. No fuel has been collected by the DOE, and spent nuclear fuel is being stored at each of the plants. Maine Yankee, Connecticut Yankee and Yankee Atomic collected the funds from wholesale utility customers, including the Company, under FERC-approved contract rates, and these payments were collected from the Company's retail customers. All three are parties to a lawsuit against the DOE seeking damages based on the DOE's default.

On February 28, 2006, all three companies asked the Court to allow amended damage claim filings to cover the period ending December 31, 2002. The request was based on a September 2005 decision by the United States Court of Appeals for the Federal Circuit involving another nuclear utility's spent fuel that, among other things, found that plaintiffs in partial breach cases were not entitled to future damages. The proposed amended damage claims are about $79 million for Maine Yankee, $82.8 million for Connecticut Yankee and $101.8 million for Yankee Atomic. This compares to original claims of $160 million for Maine Yankee, $197.1 million for Connecticut Yankee and $191 million for Yankee Atomic. The original claims covered a longer expected period including future damages. Due to the complexity of the issues and the possibility of appeals, the three companies cannot predict the amount of damages to be received or the timing of the final determination of such damages. None of the companies have included a ny allowance for potential recovery of these claims in their FERC-filed cost estimates.

Maine Yankee: The Company has a 2 percent ownership interest in Maine Yankee. On October 3, 2005, Maine Yankee completed its decommissioning efforts and the Nuclear Regulatory Commission ("NRC") amended its operating license for operation of the Independent Spent Fuel Storage Installation.

Connecticut Yankee: The Company has a 2 percent ownership interest in Connecticut Yankee. Connecticut Yankee and Bechtel Power Corporation ("Bechtel") were engaged in litigation in Connecticut Superior Court concerning Connecticut Yankee's July 2003 termination of Bechtel's decommissioning contract for default and related disputes. On March 7, 2006, the parties settled their disputes. Bechtel agreed to pay Connecticut Yankee $15.0 million, release all claims and withdraw its intervention in the Company's FERC Rate Case. Connecticut Yankee agreed to release all claims and that the decommissioning contract be deemed terminated by agreement. Connecticut Yankee expects to credit net proceeds of the settlement against decommissioning costs recoverable under the power contracts with sponsor companies. At this time, the Company cannot predict the effect, if any, this settlement will have related to the FERC Rate Case described below. To the extent any amounts of the settlement payment are ulti mately returned, these amounts will be credited for the future benefit of retail ratepayers.

Page 20 of 44

On November 22, 2005, the ALJ issued an Initial Decision on Connecticut Yankee's FERC Rate Case that it filed in July 2004. In the filing, Connecticut Yankee sought to increase its annual decommissioning collections from $16.7 million to $93 million through 2010 beginning January 1, 2005. The Initial Decision found that there was no evidence of Connecticut Yankee imprudence, as claimed by interveners in the case. The only adjustment to Connecticut Yankee's decommissioning charges required by the Initial Decision relates to the escalation rate, which is the factor used to translate the 2003 Estimate (stated in 2003 dollars) into spending projections and decommissioning charges. The Initial Decision found that Connecticut Yankee should recalculate its decommissioning charges to reflect a lower escalation rate. The Initial Decision is subject to review by FERC. Pending the FERC decision, Connecticut Yankee is charging its sponsors the filed amounts, subject to refund.

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. However, there is a risk, notwithstanding the ALJ Initial Decision, that some portion of the increased costs may not be recovered, or will have to be refunded if already recovered, as a result of the FERC proceedings. If FERC disallows cost recovery in wholesale rates, it is anticipated that the PSB would disallow these costs for recovery in retail rates as well. The timing, amount and outcome of the FERC rate case filing cannot be predicted at this time.

Yankee Atomic: The Company has a 3.5 percent ownership interest in Yankee Atomic. The decommissioning effort is largely complete and final site-work is expected to conclude in 2006. Following the completion of decommissioning, the remaining on-site function will be to operate the Independent Spent Fuel Storage Installation.

In November 2005, Yankee Atomic established an updated estimate of the cost of completing the decommissioning effort and submitted an application to FERC for increased decommissioning charges. The Company's share of the rate increase amounts to about $1.5 million for 2006 and $0.4 million annually for 2007 through 2010. On January 1, 2006, FERC issued an Order: 1) accepting Yankee Atomic's rate filing; 2) permitting the proposed rates to go into effect, subject to refund, as of February 1, 2006; and 3) referring the parties to a settlement judge to facilitate a possible settlement.

A settlement agreement among all of the parties was filed at the FERC on May 1, 2006. Under the proposed settlement agreement, Yankee Atomic agreed to reduce its November 2005 estimate from $85 million to $56.8 million. The revision includes adjustments for contingencies, projected escalation and certain decontamination and dismantlement expenses. Other terms of the proposed settlement include extending the collection period for charges through December 2014, and reconciling and adjusting future charges based on actual decontamination and dismantlement expenses and the decommissioning trust fund's actual investment earnings. The proposed settlement agreement will become effective upon approval by FERC, but the settlement should not materially affect the level of charges expected in 2006.

Millstone Unit #3 The Company has a 1.7303 percent joint ownership interest in Millstone Unit #3 and is responsible for its share of nuclear decommissioning costs. In January 2004, the lead owner Dominion Nuclear Corporation ("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. 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. On November 28, 2005, the NRC renewed the operating license for Millstone Unit #3 for an addition al 20 years. This extends the licensed life from November 2025 to November 2045.

Vermont Yankee The Company has a 35 percent entitlement in Vermont Yankee plant output sold by Entergy Nuclear Vermont Yankee, LLC ("ENVY") to VYNPC, through a long-term power purchase contract ("PPA") with VYNPC. One remaining secondary purchaser continues to receive a small percentage of the Company's entitlement, reducing its 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. The plant normally shuts down for about one month every 18 months for maintenance and to insert new fuel into the reactor.

Page 21 of 44

The plant's last scheduled refueling outage began on October 22, 2005 and the plant resumed production on November 10, 2005 followed by a three-day ramp-up to full power. Prior to the outage, the Company purchased forward supplies of replacement energy at a fixed price of about $115 per mWh for the expected outage duration to minimize exposure to spot market energy price volatility. The price for replacement power was significantly higher than what is currently being recovered in retail rates. The net cost of incremental replacement power amounted to about $5.4 million. On December 23, 2005, the Company filed a request for an Accounting Order from the PSB to defer $4.7 million of the net incremental replacement power costs for recovery in its next rate proceeding, representing the incremental amount above those already embedded in current retail rates. The Company's request also included approval to apply the $1.1 million credit it received through VYNPC power bills in 2005 to reduce the deferral. I f the PSB approves the request, the result would be a net deferral of $3.6 million for recovery in the Company's next rate proceeding.

On March 6, 2006, the DPS asked the PSB to deny the Company's request for an Accounting Order, and recommended that the $1.1 million credit and unrelated savings due to increased deliveries under the Hydro-Quebec contract be recorded as regulatory liabilities for return to ratepayers. On March 29, 2006, the PSB opened an investigation on the Company's request for an Accounting Order. In April 2006, the Company and the DPS provided prefiled testimony as requested by the PSB. The Company is not able to predict the outcome of this matter at this time.

In March 2004, the PSB approved ENVY's request to increase generation at the Vermont Yankee plant by 110 megawatts. The PSB's approval included a condition that ENVY provide outage protection indemnification ("Ratepayer Protection Proposal" or "RPP") for times the uprate causes reductions in output that reduce the value of the PPA. The Company's maximum right to indemnification under the RPP is about $2.8 million for the three-year period beginning in May 2004 and ending after completion of the uprate (or a maximum of three years).

On March 2, 2006, the NRC gave final approval to the uprate. Since that time Vermont Yankee plant output has slowly increased to the expected uprate level of 120 percent. Some time after completion of the uprate, the plant will receive a new output rating and the Company's share of the plant's rating should be equivalent to the amount it received before the uprate process began. There is a risk that the Company's percentage of energy output may decline if the plant needs to reduce output after the uprate. The Company estimates that this could have a material adverse effect on net power costs.

On March 16, 2006, the Company, Green Mountain Power, ENVY and the DPS filed a settlement with the PSB resolving all issues raised in a petition before the PSB regarding the RPP, including recovery of incremental replacement power costs associated with a June 2004 outage at the plant and reduced output due to the uprate. The settlement would resolve all issues through February 28, 2006. The Company's share of the settlement is estimated to be about $1.6 million including $0.7 million related to the June 2004 outage and the remaining for uprate-related costs. Pursuant to the Rate Order, any partial or full reimbursement received by the Company from ENVY under the RPP shall be recorded as a regulatory liability for return to ratepayers in the Company's next rate proceeding. The settlement is not effective until the PSB issues a final order. The Company cannot predict the timing or outcome of this matter at this time.

ENVY had announced that it could be required to shut down the Vermont Yankee plant in 2007 or 2008 if dry cask storage of its nuclear waste (spent fuel) was not approved. In early June 2005, the Vermont State Legislature passed a law authorizing ENVY to construct and use dry cask storage facilities on the site through its current license, but required that Entergy return to the Legislature for permission to continue doing so past 2012, when its federal operating license expires. On April 26, 2006, the PSB issued its approval for dry cask storage for spent nuclear fuel through 2012.

If the Vermont Yankee plant is shut down for any reason prior to the end of its operating license, the Company would lose about 50 percent of its committed energy supply and would have to acquire replacement power resources comprising about 40 percent of its estimated power supply needs. Based on projected market prices, the incremental cost of lost power is estimated to average about $55 million on an annual basis. Based on this estimate, the Company would require a retail rate increase of about 20 percent for full cost recovery. The Company is not able to predict whether there will be an early shutdown of the Vermont Yankee plant or whether the PSB will allow timely and full recovery of increased costs related to any such shutdown. The implications of an early shut down of the Vermont Yankee plant could have a material effect on the Company's financial position and future results of operations, if those costs are not recovered in retail rates in a timely fashion.

Page 22 of 44

Hydro-Quebec The Company is purchasing varying amounts of power from Hydro-Quebec under the Vermont Joint Owners ("VJO") Power Contract through 2016. The VJO includes a group of Vermont electric companies and municipal utilities, of which the Company is a participant. There are specific contractual provisions that provide that in the event any VJO member fails to meet its obligation under the contract with Hydro-Quebec, the balance of the VJO participants, including the Company, will "step-up" to the defaulting party's share on a pro-rata basis. The VJO contract runs through 2020, but the Company's purchases related to the contract end in 2016.

In the early phase of the VJO Power Contract, two sellback contracts were negotiated, the first delaying the purchase of 25 MW of capacity and associated energy, the second reducing the net purchase of Hydro-Quebec power through 1996. In 1994, the Company negotiated a third sellback arrangement whereby it received a reduction in capacity costs from 1995 to 1999. In exchange for this sellback, Hydro-Quebec obtained two options. The first gives Hydro-Quebec the right upon four years written notice, to reduce capacity deliveries by 50 MW beginning as early as 2010, including the use of a like amount of the Company's Phase I/II transmission facility rights. The second gives Hydro-Quebec the right, upon one years written notice, to curtail energy deliveries in a contract year (12 months beginning November 1) from an annual load factor of 75 to 50 percent due to adverse hydraulic conditions in Quebec. This second option can be exercised five times through October 2015.

Performance Assurance At March 31, 2006, the Company had posted $7.1 million of collateral under performance assurance requirements for certain of its power contracts. These payments are included in Special Deposits on the Condensed Consolidated Balance Sheet. Performance assurance requirements are described in more detail below.

The Company is subject to performance assurance requirements associated with its power purchase and sale transactions through ISO-New England under the Financial Assurance Policy for NEPOOL members. At the Company's current credit rating of 'BB+', the credit limit with ISO-New England is zero and the Company is required to post collateral for all net purchase transactions. ISO-New England reviews collateral requirements on a daily basis. As of March 31, 2006, the Company posted $3.9 million of collateral with ISO-New England.

The Company is currently selling power in the wholesale market pursuant to two third-party contracts covering periods through late 2006 and late 2008. Under both of these contracts, the Company is required to post collateral if its credit rating is downgraded below investment-grade status, but only if requested to do so by the counterparties. As of March 31, 2006, the Company posted $3.2 million of collateral related to one of the third-party contracts. This collateral requirement is reviewed on a weekly basis. On April 5, 2006, the Company initially posted $8.6 million related to a request by the other third party to post collateral under the power contract with them. This collateral requirement can be reviewed on a daily basis by either party.

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

Environmental Over the years, more than 100 companies have merged into or been acquired by the Company. At least two of 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.

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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 at the 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, Public Service Company of New Hampshire ("PSNH") contacted the Company about this site. PSNH alleged that the Company was partially liable for cleanup, since the site was previously operated by Twin State Gas and Electric, which merged into the Company the same day that PSNH bought the facility. In 2002, the Company reached a settlement with PSNH in which certain liabilities it might have had were assigned to PSNH in return for a cash settlement paid by the Company based on completion of PSNH's cleanup effort. The Company's remaining obligation related to this settlement is less than $0.1 million.

As of March 31, 2006, a $5.4 million reserve for environmental matters is recorded on the Condensed Consolidated Balance Sheet. At December 31, 2005, the reserve was $5.4 million. The reserve represents Management's best estimate of the cost to remedy issues at these sites based on available information ranging from a high of $7.6 million to a low of $4.5 million. 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 Indemnifications Under the terms of the agreements with Catamount and Diamond Castle, the Company agreed to indemnify them, and certain of their respective affiliates, in respect of a breach of certain representations and warranties and covenants, most of which survive until June 30, 2007, except certain items that customarily survive indefinitely. Indemnification is subject to a $1.5 million deductible and a $15.0 million cap, excluding certain customary items. Environmental representations are subject to the deductible and the cap, and such environmental representations for only two of Catamount's underlying energy projects survive beyond June 30, 2007. In the fourth quarter of 2005, the Company recorded a $0.3 million contingent liability related to one of Catamount's projects. This amount represents the Company's estimate of the fair value of the indemnification which is not subject to the deductible. The Company's estimated "maximum potential" amount of future payments rela ted to these indemnifications is limited to $15.0 million. The Company has not recorded any additional liability related to these indemnifications.

Legal Proceedings The Company is involved in legal and administrative proceedings in the normal course of business and does not believe that the ultimate outcome of these proceedings will have a material adverse effect on its financial position or results of operations, except as otherwise disclosed herein.

NOTE 9 - 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; 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; and Catamount Resources & Other, which includes Catamount Resources Corporation ("Catamount Resources") and C.V. Realty, Inc. Catamount Resources was formed to hold the Company's subsidiaries that invest in unregulated business opportunities, and C.V. Realty, Inc. is a real estate company whose purpose is to own,

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acquire, buy, sell and lease real and personal property and interests therein related to the utility business. Its operations and assets are below the quantitative threshold tests; therefore, C.V. Realty is included in Catamount Resources and Other. Discontinued Operations includes Catamount as described in Note 4 - Discontinued Operations.

The accounting policies of operating segments are the same as those described in the summary of significant accounting policies. Inter-segment revenues include revenues for support services, including allocations of software systems and equipment, to Eversant. Financial information by segment for the first quarters of 2006 and 2005 is as follows (in thousands):

THREE MONTHS ENDED MARCH 31	CV VT	Eversant Corporation	Catamount Resources and Other	Discontinued Operations	Reclassification and Consolidating Entries	Consolidated
2006
Revenues from external customers Inter-segment revenues Equity in earnings from affiliates Income from continuing operations Total assets at March 31, 2006	$82,255 3 517 3,652 471,176	$450 - - - - 92 1,893	- - - - - $353 54,144	- - - - - - - - -	$(450) (3) - - - - (702)	$82,255 - - 517 4,097 526,511
2005
Revenues from external customers Inter-segment revenues Equity in earnings from affiliates Rate Order charges (1) (Loss) income from continuing operations Income from discontinued operations, net of tax Total assets at December 31, 2005	$75,664 1 483 21,771 (5,038) - - 496,483	$457 - - - - - - 120 - - 1,824	- - - - - - - $3 - - 58,780	- - - - - - - - - $288 - -	$(457) (1) - - - - - - - - (5,654)	$75,664 - - 483 21,771 (4,915) 288 551,433
(1) See Note 3 - Retail Rates and Regulatory Accounting.

NOTE 10 - SUBSEQUENT EVENTS
Tender Offer On February 7, 2006, the Company announced that its Board of Directors approved using about $50.0 million in proceeds from the December 20, 2005 sale of Catamount to buy back shares of its common stock in a reverse Dutch auction tender offer. The tender offer commenced on February 14, 2006 and was scheduled to expire on March 15, 2006, but the Company extended it until April 5, 2006. Under the procedures of the tender offer, shareholders could offer to sell some or all of their stock to the Company at a target price in a range from $20.50 to $22.50 per share. Upon expiration of the tender offer, the Company selected the lowest-bid price that would allow it to buy up to 2,250,000 shares, representing about 18.3 percent of the Company's outstanding common stock.

On April 19, 2006, the Company announced that the final results of the tender offer were that the Company purchased 2,249,975 shares of common stock at an average price of $22.50 per share of common stock. As a result the Company's common stock outstanding has been reduced to about 10,051,940.

Rochester Electric On April 6, 2006, the Company entered into an agreement to purchase Rochester Electric Light and Power at net book value. Rochester Electric Light and Power is a privately owned electric utility with a principal place of business in Rochester, Vermont, serving about 900-plus customers. The agreement includes purchase of the retail electric and distribution system and facilities in Rochester, Stockbridge, and Pittsfield, Vermont, a 0.17 percent interest in the Highgate Converter located in Highgate, and Rochester's share of the VJO Power Contract with Hydro-Quebec. The purchase price is about $250,000, and the transaction is expected to be completed in mid to late 2006. The purchase requires prior approval of the PSB.

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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 or improve our current credit ratings; and
other considerations such as the operations of ISO-New England, changes in the cost or availability of capital, authoritative accounting guidance and the effect of the volatility in the equity markets on pension benefit and other costs.

We cannot predict the outcome of any of these matters; accordingly, there can be no assurance 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 SUMMARY
We are a Vermont-based electric utility that transmits, distributes and sells electricity. We are regulated by the Vermont Public Service Board ("PSB"), the Connecticut Department of Public Utility Control and the Federal Energy Regulatory Commission ("FERC"), with respect to rates charged for service, accounting, financing and other matters pertaining to regulated operations. Our retail rates are set by the PSB after considering recommendations of Vermont's consumer advocate, the Vermont Department of Public Service ("DPS"). Fair regulatory treatment is fundamental to maintaining our financial stability. Rates must be set at levels to recover costs, including a market rate of return to equity and debt holders, in order to attract capital.

Our non-regulated wholly owned subsidiary Catamount Resources Corporation ("CRC") owns Eversant Corporation ("Eversant"), which operates a rental water heater business through its wholly owned subsidiary, SmartEnergy Water Heating Services, Inc. On December 20, 2005, CRC sold all of its interest in Catamount Energy Corporation ("Catamount"), which invested primarily in wind energy projects in the United States and the United Kingdom, to CEC Wind Acquisition, LLC, a Delaware limited liability company established by Diamond Castle Holdings ("Diamond Castle"). We began reporting Catamount as discontinued operations in the fourth quarter of 2005, and its first-quarter 2005 results have been reclassified to conform to this presentation.

Other wholly owned subsidiaries include Custom Investment Corporation ("Custom"), a passive investment subsidiary that holds our investment in Vermont Yankee Nuclear Power Corporation ("VYNPC"), and Connecticut Valley, which completed the sale of substantially all of its plant assets and franchise to Public Service Company of New Hampshire ("PSNH") on January 1, 2004.

Our consolidated first-quarter 2006 earnings were $4.1 million, or 32 cents per diluted share of common stock. This compares to a first-quarter 2005 loss of $4.6 million, or 39 cents per diluted share of common stock. First-quarter 2005 results included a $21.8 million pre-tax charge to earnings, or 91 cents per diluted share of common stock, related to the PSB's Order issued on March 29, 2005 ("Rate Order"). The primary drivers of first-quarter 2006 results versus the same period in 2005 are described in detail in Results of Operations below.

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The second-quarter 2005 downgrade of our credit rating to below investment grade, has had a significant affect on our liquidity. We are now required to post collateral under performance assurance requirements for certain of our power contracts. As of May 8, 2006 our total estimated collateral requirement was about $13.8 million. We have a $25.0 million unsecured credit facility available to support operating needs including the posting of collateral. At March 31, 2006 there were no borrowings or letters of credit outstanding under this facility. Although we have taken steps to help ensure liquidity is maintained over the next two years, an unscheduled and prolonged outage of one of our significant power sources such as Vermont Yankee or Hydro-Quebec could have a detrimental effect on our liquidity without some form of rapid rate relief from our regulators.

Achieving investment-grade status and improving communications with our Vermont regulators are top priorities for us. Our ongoing liquidity and ability to make necessary investments in our electric system could be greatly impacted without a combination of a rate increase within the next 18 months and ongoing efforts to control rising costs. We are in the process of preparing a request for a rate increase, which we expect to file with the PSB by the end of May for retail rates effective in the first quarter of 2007.

We believe restoration of the Company's credit rating is critical, not only to the long-term success of the Company, but to Vermont's energy future. While our credit rating remains below investment-grade the cost of capital, which is ultimately passed on to our customers, will be greater than it otherwise would be. That combined with other collateral requirements from creditors and for power purchases makes restoration of our credit rating critical. Looking ahead, as long-term power contracts with Hydro-Quebec and Vermont Yankee begin to expire six years from now, this rating becomes even more important.

The PSB has not yet issued its decision on our December 2005 request for an Accounting Order to defer about $4.7 million of net incremental replacement power costs that we incurred for a Vermont Yankee scheduled refueling outage. In our request we had proposed offsetting these costs with a $1.1 million credit that we received from Vermont Yankee in 2005. This would result in a net deferral of about $3.6 million. If the PSB approves our request in full or in part, the costs would be reversed in 2006, since we were not allowed to defer them in 2005. See Power Supply Matters below.

Our tender offer to purchase 2,250,000 shares of the Company's common stock concluded on April 5, 2006. As a result, in mid-April 2006, we purchased 2,249,975 shares, reducing the number of outstanding shares by about 18.3 percent. We used about $50.0 million of the cash proceeds from the Catamount sale for this transaction. The stock buyback will reduce our overall dividend obligations while increasing the per-share ownership interest for remaining shareholders.

RETAIL RATES
Adequate and timely rate relief is required to maintain our financial strength, particularly since Vermont law does not allow purchased power and fuel costs to be passed on to consumers through purchased power and fuel adjustment clauses. We will continue to review costs and request rate increases when warranted. Our current retail rates are based on a March 29, 2005 PSB Order ("Rate Order") that when finalized included, among other things, the following: 1) a 2.75 percent rate reduction beginning April 1, 2005; 2) a $6.5 million pre-tax refund to customers; 3) a 10 percent return on equity (reduced from 11 percent); and 4) a requirement that the gain resulting from termination of the power contract related to the 2004 Connecticut Valley sale be applied to the benefit of ratepayers to compensate for increased costs. The Rate Order resulted in a $21.8 million pre-tax unfavorable effect on utility earnings in the first quarter of 2005.

On June 22, 2005, we filed an appeal of portions of the Rate Order with the Vermont Supreme Court. On July 11, 2005, we filed a docketing statement with the court in which we outlined the issues in our case. The docketing statement describes the ordered payback of earnings from periods prior to the opening of the rate investigation, namely the years 2001 to 2003, and also the first quarter of 2004 when we recorded a gain from the Connecticut Valley sale. The issues that were raised on appeal primarily focus on whether the Rate Order sets rates retroactively without statutory authorization. On July 27, 2005, the DPS filed a response opposing our position. We filed our legal brief and other materials in the case on August 22, 2005. Expedited oral argument occurred on January 31, 2006, and we expect a Vermont Supreme Court decision on the case in the second or third quarter of 2006. We are not able to predict the outcome of this matter at this time.

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LIQUIDITY AND CAPITAL RESOURCES
Liquidity

At March 31, 2006, we had cash and cash equivalents of $17.9 million included in total working capital of $84.0 million. During the first quarter of 2006, cash and cash equivalents increased by $11.3 million. The increase resulted from the following:

Operating Activities of Continuing Operations: Operating activities provided $6.2 million. Net income, when adjusted for depreciation, amortization, deferred income tax and other items provided about $7.7 million. Additionally, collateral requirements under certain power contracts decreased by $11.9 million and changes in working capital and other items provided $3.4 million. This was partially offset by a $12.2 million pension trust fund contribution, $4.1 million in postretirement trust fund contributions, and $0.7 million in postretirement out-of-pocket payments, offset by $0.2 million of contributions received from plan participants.

Investing Activities of Continuing Operations: Investing activities provided $8.4 million, including $13.4 million in proceeds from net sales and maturities of available-for-sale securities, partially offset by $5.0 million of construction expenditures.

Financing Activities of Continuing Operations: Financing activities used $3.3 million, including $3.0 million for dividends paid on common and preferred stock, $0.3 million for capital lease payments and $0.3 million for costs related to the tender offer, partially offset by $0.2 million from stock issuance proceeds relating to stock option exercises and $0.1 million of other items.

Available-for-sale Securities: Investments in available-for-sale securities at March 31, 2006 include $60.6 million with original maturities from 90 days to one year and $3.9 million with original maturities greater than one year. In mid-April 2006 we used about $50.0 million of the Catamount sale proceeds to repurchase shares of our common stock based on the tender offer that concluded on April 5, 2006.

VELCO: We continue to consider additional investments in VELCO at a level intended to maintain VELCO's common equity at 25 percent of its total capitalization. In total, our investments in VELCO could amount to between $35 million and $40 million through 2008. Based on VELCO's current projections, we could invest about $20 million to $25 million in 2006, $11 million to $13 million in 2007, and $2 million to $4 million in 2008. VELCO's equity projections are subject to change based on a number of factors, including revised upgrade estimates and timing of regulatory approvals. Our investment plans in VELCO are also subject to change due to circumstances such as liquidity deterioration.

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

Rate Order: Our retail rates were reduced by 2.75 percent ($7.2 million pre-tax on an annual basis) on April 1, 2005. The rate reduction combined with the 10 percent allowed return on equity (reduced from 11 percent) will impact our cash flow from operations in future years. We are in the process of preparing a request for a rate increase, which we expect to file with the PSB by the end of May for retail rates effective in the first quarter of 2007.

Other: In the first quarter of 2006, we made $16.3 million of additional contributions to our pension and postretirement medical funds. Additionally, we expect to make capital expenditures of about $18 million in 2006. In the first quarter of 2006, we reached an agreement to purchase Rochester Electric Light and Power at net book value. Rochester Electric Light and Power is a privately owned electric utility with a principal place of business in Rochester, Vermont, serving about 900-plus customers. The purchase, for about $250,000, requires approval by the PSB.

Cash Flow Risks: We believe that cash on hand, including available-for-sale securities, cash flow from operations and our $25.0 million credit facility will be sufficient to fund our business for the next 12 months. Based on our current cash forecasts, the borrowing capacity under our $25.0 million credit facility will likely provide sufficient liquidity at least through 2007. However, an extended Vermont Yankee plant outage or similar event could significantly impact our liquidity due to the potential high cost of replacement power and performance assurance collateral requirements arising from purchases through ISO-New England or third parties. In the event of an extended Vermont Yankee plant outage, we

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could seek emergency rate relief from our regulators. Other material risks to cash flow from operations include: loss of retail sales revenue from unusual weather; slower-than-anticipated load growth and unfavorable economic conditions; increases in net power costs largely due to lower-than-anticipated margins on sales revenue from excess power or an unexpected power source interruption; required prepayments for power purchases; and increases in performance assurance collateral requirements described below, primarily as a result of high power market prices.

Financing

Long-Term Debt and Short-term Notes Payable: Scheduled sinking fund payments for the next five years are $0 in 2006, $0 in 2007, $3.0 million in 2008, $5.5 million in 2009, and $0 in 2010. 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.

Credit Facility: On October 27, 2005, we closed on a three-year, $25.0 million unsecured revolving-credit facility with a lending institution pursuant to a Credit Agreement dated October 21, 2005. At March 31, 2006 there were no borrowings or letters of credit outstanding under this facility.

Covenants: At March 31, 2006, we were in compliance with all covenants related to our various debt agreements, Articles of Association, letters of credit and credit facility; these agreements contain both financial and non-financial covenants.

Performance Assurance
As of March 31, 2006, we had posted $7.1 million of collateral under performance assurance requirements for certain of our power contracts, primarily as a result of the credit rating downgrades to below investment grade. We believe that we have sufficient liquidity to meet the performance assurance requirements as described below.

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. At our current credit rating of 'BB+', our credit limit with ISO-New England is zero and we are required to post collateral for all net purchase transactions. ISO-New England reviews our collateral requirements on a daily basis. As of March 31, 2006, we had posted $3.9 million of collateral with ISO-New England.

We are currently selling power in the wholesale market pursuant to two third-party contracts covering periods through late 2006 and late 2008. Under both of these contracts, we are required to post collateral if our credit rating is downgraded below investment-grade status, but only if requested to do so by the counterparties. As of March 31, 2006, we posted $3.2 million of collateral related to one of the third-party contracts. This collateral requirement is reviewed on a weekly basis. On April 5, 2006, we initially posted $8.6 million related to a request by the other third party to post collateral under the power contract with them. This collateral requirement can be reviewed on a daily basis by either party. As of May 8, 2006, our total collateral requirement under these contracts is estimated to be about $12.9 million. Our estimates are based on current estimates of forward market prices. Depending on the difference between the contract price and the market price of power, these estimates could i ncrease or decrease significantly.

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

Future risks to performance assurance requirements include collateral calls on the contracts described above, increasing power market prices, and an extended Vermont Yankee outage or other unexpected interruption of a major power source that would require us to purchase replacement power through ISO-New England or other third parties.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our financial statements are prepared in accordance with generally accepted accounting principles in the United States ("GAAP"), requiring us to make estimates and judgments that affect reported amounts of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of the Condensed Consolidated Financial Statements. See Critical Accounting Policies and Estimates in Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2005 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 2005 Form 10-K.

Regulation We prepare our financial statements in accordance with Statement of Financial Accounting Standards No. 71 ("SFAS No. 71") for our regulated Vermont service territory and FERC-regulated wholesale business. Under SFAS No. 71, we account for certain transactions in accordance with permitted regulatory treatment. 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.

Based on a current evaluation of the factors and conditions expected to impact future cost recovery, we believe future recovery of our regulatory assets in the State of Vermont for our 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 $29.9 million pre-tax as of March 31, 2006. We would also be required to determine any impairment to the carrying costs of deregulated plant.

Pension and Postretirement Benefits Pension costs reflected in results of operations were $1.3 million in the first quarter of 2006 compared to $1.1 million in the first quarter of 2005. Of these amounts, a small amount is capitalized. Postretirement costs reflected in results of operations were $0.9 million in the first quarter of 2006 compared to $0.7 million in the first quarter of 2005. Of these amounts, a small amount is capitalized.

At March 31, 2006, the fair value of Pension Plan trust assets was $78.6 million, including $55.5 million in marketable equity securities and $23.1 million in debt securities. At December 31, 2005, the fair value of Pension Plan trust assets was $66.4 million, including $45.7 million in marketable equity securities and $20.7 million in debt securities. In March 2006, we contributed an additional $12.2 million to the Pension Plan.

Derivative Financial Instruments
We account for various power contracts as derivatives under the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted and SFAS No. 149, Amendment of Statement 133 Derivative Instruments and Hedging Activities, (collectively "SFAS No. 133"). These statements require that derivatives be recorded on the balance sheets at fair value.

We have a long-term purchased power contract that allows the seller to repurchase specified amounts of power with advance notice (Hydro-Quebec Sellback #3). This contract has been determined to be a derivative under SFAS No. 133. The derivative's estimated fair value was an unrealized loss of $4.3 million at March 31, 2006 and $5.0 million at December 31, 2005. The estimated fair value of this derivative is valued using a binomial tree model, and quoted market data when available along with appropriate valuation methodologies.

We have a long-term forward sale contract for the sale of about 15 MW per hour, or a total of 522,544 mWh, beginning November 17, 2004 through December 31, 2008. As of March 31, 2006, about 175,376 mWh have been delivered under the contract. This contract has been determined to be a derivative under SFAS No. 133. We utilize over-the-counter quotations or broker quotes at the end of the reporting period for determining the fair value of this contract. The derivative's estimated fair value was an unrealized loss of $9.0 million at March 31, 2006 and $12.9 million at December 31, 2005.

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

RESULTS OF OPERATIONS
The following is a detailed discussion of the Company's results of operations for the first quarter of 2006 compared to the same period in 2005. This should be read in conjunction with the condensed consolidated financial statements and accompanying notes included in this report.

Consolidated Summary
First-quarter 2006 consolidated earnings were $4.1 million, or 33 cents per basic and 32 cents per diluted share of common stock. This compares to a first-quarter 2005 loss of $4.6 million, or 39 cents per basic and diluted share of common stock. First quarter 2005 results included a $21.8 million pre-tax charge to earnings, or 91 cents per diluted share of common stock, related to the Rate Order. First-quarter 2005 results also included earnings from discontinued operations of $0.3 million, or 2 cents per basic and diluted share of common stock, related to Catamount. The following table provides a reconciliation of 2006 versus 2005 diluted earnings per share.

2005 Loss per diluted share		$(.39)

Year-over-Year Effects on Earnings:
Higher resale revenue	.12
CRC higher earnings in 2006	.03
Lower retail revenue (a)	(.09)
Higher other operating costs (a)	(.15)
Higher purchased power costs (a)	(.15)
Other	.06
Subtotal		(.18)

Net impact of one-time 2005 Rate Order charge		.91
Discontinued operations - 2005 earnings		(.02)

2006 Earnings per diluted share		$.32

(a) - Excludes 2005 Rate Order charges.

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 electric sales. Resale sales are related to the sale of excess power from our owned and purchased power supply portfolio. Operating revenues and related mWh sales are summarized below:

	Three months ended March 31,
	mWh Sales		Revenues (in thousands)
	2006	2005	2006	2005
Retail sales: Residential Commercial Industrial Other retail Total retail sales Resale sales Retail customer refund Other revenues Total	266,945 216,659 114,820 1,510 599,934 214,815 - - 814,749	273,678 217,063 109,158 1,331 601,230 152,532 - - - 753,762	$33,674 25,003 9,701 436 68,814 11,538 - 1,903 $82,255	$35,287 25,708 9,347 393 70,735 8,971 (6,197) 2,155 $75,664

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Operating revenues increased $6.6 million, or 8.7 percent, in the first quarter of 2006 compared to the same period in 2005, due to the following factors:

Retail sales decreased $1.9 million due to a 2.75 percent rate reduction that began in April 2005 as a result of the Rate Order.
Resale sales increased $2.6 million primarily due to $3.5 million in higher sales volume as more mWh were available from long-term power contracts, offset by $0.9 million of lower average contract prices on forward sales.
The PSB-required retail customer refund reduced revenue by $6.2 million in 2005, resulting in a favorable variance when compared to 2006. The Rate Order required the refund for amounts determined by the PSB as over-collections during the period April 7, 2004 through March 31, 2005. Of the $6.2 million, $1.7 million was attributed to 2005 and $4.5 million was attributed to 2004.
Other revenues decreased about $0.3 million due to lower transmission revenue and other third party billings.

Purchased Power Our purchases of power constituted about 55 percent of total operating expenses in the first quarters of 2006 and 2005. Most of our power purchases are made under long-term contracts. These contracts and other power supply matters are discussed in more detail in Power Supply Matters below. Purchased power expense and related mWh purchases are summarized below:

	Three months ended March 31,
	mWh Purchases		Purchases (in thousands)
	2006	2005	2006	2005
VYNPC (a) Hydro-Quebec Independent Power Producers subtotal long-term contracts Short-term and miscellaneous purchases SFAS No. 5 loss amortizations Maine Yankee, Connecticut Yankee and Yankee Atomic (a) March 29, 2005 Rate Order Other Total purchased power	392,485 255,515 50,694 698,694 25,375 - - - - - - - 724,069	379,974 228,916 32,958 641,848 37,874 - - - - - - - 679,722	$15,908 16,232 6,683 38,823 2,473 (299) 1,365 - - 126 $42,488	$15,216 15,171 4,569 34,956 3,931 (299) 790 2,441 28 $41,847
(a) Purchased power transactions with affiliates. Amounts shown in the table above are adjusted for regulatory amortizations and deferrals including our share of VYNPC nuclear insurance settlements of about $0.5 million in each period that we deferred per PSB approval, and deferral of Yankee Atomic incremental dismantling costs prior to April 1, 2005, when they were eliminated in accordance with the Rate Order.

Purchased power expense increased $0.6 million, or 1.5 percent, in the first quarter of 2006 compared to the same period in 2005 due to the following factors:

Long-term purchases increased $3.9 million primarily related to: 1) higher Vermont Yankee plant output because the uprate to increase plant capacity by 20 percent started in March 2006; 2) more deliveries from Hydro-Quebec due to an increase in the load factor for the annual contract year beginning November 1, 2005; and 3) higher output from Independent Power Producers, the majority of which are hydro facilities and output is based on weather conditions that affect water flow. Since there were more mWh purchased from these sources, the $3.9 million increase is partially offset by higher resale sales and fewer short-term purchases.
Short-term purchases decreased $1.5 million primarily related to more mWh available from long-term contracts and wholly and jointly owned generating units.
Power costs for Maine Yankee, Connecticut Yankee and Yankee Atomic are primarily related to decommissioning activities at each of the plants. These costs increased by about $0.6 million due to higher FERC-approved rates and elimination of accounting deferrals in 2005 per the Rate Order. Our obligations related to these plants are described in Nuclear Generating Units below.
Accounting entries related to the Rate Order increased 2005 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. The Rate Order charge results in a favorable variance when comparing 2006 versus 2005.
Other power costs increased about $0.1 million.

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Operating Expenses Operating expenses represent costs incurred to support our core business. Operating expenses increased $1.0 million in 2006 versus 2005, including $0.6 million related to purchased power described above. The remaining $0.4 million increase is primarily related to the income statement line items discussed below.

Transmission - affiliates and other: These expenses are associated with transmission of electricity. The $0.4 million increase in 2006 is primarily related to higher VELCO demand-based charges.

Other operation: These expenses are related to operating activity such as customer accounting, customer service, administrative and general, regulatory deferrals and amortizations, and other operating costs incurred to support our core business. The $10.0 million decrease in 2006, reflects the impact of first-quarter 2005 Rate Order charges of $10.7 million. The remaining $0.7 million increase was due to higher external audit fees and higher employee-related costs including medical and pension costs, partly offset by lower regulatory amortizations that beginning in April 2005. The $10.7 million Rate Order charge primarily resulted from the revised calculation of overearnings for 2001 - 2003 and application of the 2004 gain resulting from termination of the power contract with Connecticut Valley.

Maintenance: These expenses are related to costs associated with maintaining our electric distribution system and include costs from our jointly owned generating and transmission facilities. The $1.9 million increase in 2006 is related to higher storm restoration costs in the first quarter of 2006 and higher contractor costs for tree trimming.

Taxes on Income: Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences, tax credits, tax settlements and changes in valuation allowances for the periods. The $7.9 million increase reflects the effect of the first-quarter 2005 Rate Order charges. The effective tax rate was 34.6 percent for the first quarter of 2006, compared to 56.0 percent for the first quarter of 2005.

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 $2.2 million increase in 2006 is primarily related to the income statement line items discussed below.

Other income: These income items include non-operating rental income mostly from rental water heaters, interest and dividend income, interest on temporary investments and various miscellaneous other income items. The $1.7 million increase in 2006 includes first-quarter 2005 Rate Order charges of $0.8 million. The remaining $0.9 million increase is primarily related to interest income on the Catamount sale proceeds and a $0.3 million gain on sales of non-utility property. The Rate Order charge was related to adjustments to carrying charges for deferred Vermont Yankee sale costs and Vermont Yankee fuel rod costs.

Other Deductions: These deductions include supplemental retirement benefits and insurance, including changes in the cash surrender value of life insurance policies, non-utility expenses relating to rental water heaters, and miscellaneous other deductions. The $1.0 million decrease in 2006, includes $0.4 million related to a first-quarter 2005 rate Order charge due to disallowance of a portion of Vermont Yankee fuel rod costs. The remaining $0.6 million decrease is primarily related to the 2005 impairment and realized losses associated with certain available-for-sale debt securities that were sold earlier than planned.

Benefit (provision) for income taxes: Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences, tax credits, tax settlements and changes in valuation allowances for the periods. The $0.5 million increase reflects 2005 tax benefits associated with the Rate Order.

Interest Expense Interest expense includes interest on long-term debt, dividends associated with mandatory redeemable preferred stock and other interest that includes interest on notes payable and credit facility. The $1.2 million decrease in 2006 is primarily related to the income statement line items discussed below.

Other interest expense: The $1.2 million decrease is related to first-quarter 2005 Rate Order charges to adjust carrying costs associated with the recalculation of overearnings for 2001 - 2003.

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Discontinued Operations The sale of Catamount to Diamond Castle was consummated on December 20, 2005. Catamount's results of operations included in discontinued operations reflect the reallocation of certain corporate costs back to continuing operations since they were not eliminated by the sale. Reversal of these costs is reflected in Catamount's operating expenses, net of income tax, in the summary of Catamount's results of operations below (in thousands).

Dividends Declared Per Share of Common Stock In December 2005, we declared a cash dividend of 23 cents per share of common stock for payment to common shareholders in February 2006. This compares to cash dividends of 23 cents per share of common stock declared in January 2005 for payment to common shareholders in February 2005, and cash dividends declared in February 2005 for payment to common shareholders in May 2005. Based on our dividend declaration schedule, cash dividends declared on common stock are typically paid to common shareholders on a quarterly basis.

POWER SUPPLY MATTERS
Our material power supply contracts are principally with Hydro-Quebec and VYNPC. These relatively low-priced contracts comprise the majority of our total annual energy (mWh) purchases. If one or both of these sources becomes unavailable for a period of time, there could be exposure to high wholesale power prices and that amount could be material.

We are responsible for procuring replacement energy during periods of scheduled or unscheduled outages at the Vermont Yankee plant. We sometimes experience energy delivery deficiencies under the power contract with Hydro-Quebec as a result of outages or other problems with the transmission interconnection facilities over which we schedule deliveries. In both cases, we purchase replacement energy, if needed, from third parties in New England or through ISO-New England. Although our retail rates include a provision for estimated replacement power costs, average market prices at the times when we purchase replacement energy might be significantly higher than amounts included for recovery in our retail rates.

Our contract for power purchases from VYNPC ends in 2012, but there is a risk that the plant could be shut down earlier than expected if Entergy determines that it is not economical to continue operating the plant under the current regulatory environment. Our contract for power purchases from Hydro-Quebec ends in 2016, although the level of deliveries will be reduced significantly in 2012. There is a risk that future sources available to replace these contracts may not be as reliable and the price of such replacement power could be significantly higher than what we have in place today.

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Hydro-Quebec: We purchase a significant part of our 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 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. The VJO contract runs through 2020, but our purchases related to the contract end in 2016.

In the early phase of the VJO Power Contract, two sellback contracts were negotiated, the first delaying the purchase of 25 MW of capacity and associated energy, the second reducing the net purchase of Hydro-Quebec power through 1996. In 1994, we negotiated a third sellback arrangement whereby we received a reduction in capacity costs from 1995 to 1999. In exchange for this sellback, Hydro-Quebec obtained two options. The first gives Hydro-Quebec the right upon four years written notice, to reduce capacity deliveries by 50 MW beginning as early as 2010, including the use of a like amount of the Company's Phase I/II transmission facility rights. The second gives Hydro-Quebec the right, upon one years written notice, to curtail energy deliveries in a contract year (12 months beginning November 1) from an annual load factor of 75 to 50 percent due to adverse hydraulic conditions in Quebec. This second option can be exercised five times through October 2015.

Under the VJO Power Contract, the VJO can elect to change the annual load factor from 75 percent to between 70 and 80 percent five times through 2020, while Hydro-Quebec can elect to reduce the load factor to not less than 65 percent three times during the same period of time. Hydro-Quebec has used all of its elections, resulting in a 65 percent load factor obligation from November 1, 2002 to October 31, 2005. The VJO elected to purchase at an 80 percent load factor for the current contract year beginning November 1, 2005 and ending October 31, 2006. The VJO now have one load factor election remaining.

VYNPC: We have a 35 percent entitlement in Vermont Yankee plant output sold by Entergy Nuclear Vermont Yankee, LLC ("ENVY") to VYNPC, through a long-term power purchase contract ("PPA") 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. The plant normally shuts down for about one month every 18 months for maintenance and to insert new fuel into the reactor.

The plant's last scheduled refueling outage began on October 22, 2005 and the plant resumed production on November 10, 2005 followed by a three-day ramp-up to full power. Prior to the outage, we purchased forward supplies of replacement energy at a fixed price of about $115 per mWh for the expected outage duration to minimize exposure to spot market energy price volatility. The price for replacement power was significantly higher than what is currently being recovered in retail rates. The net cost of incremental replacement power amounted to about $5.4 million. On December 23, 2005, we filed a request for an Accounting Order from the PSB to defer $4.7 million of the net incremental replacement power costs for recovery in our next rate proceeding, representing the incremental amount above those already embedded in current retail rates. Our request also included approval to apply the $1.1 million credit we received through VYNPC power bills in 2005 to reduce the deferral. If the PSB approves our request, the result would be a net deferral of $3.6 million for recovery in our next rate proceeding.

On March 6, 2006, the DPS asked the PSB to deny our request for an Accounting Order, and recommended that the $1.1 million credit and unrelated savings due to increased deliveries under the Hydro-Quebec contract be recorded as regulatory liabilities for return to ratepayers. On March 29, 2006, the PSB opened an investigation on our request for an Accounting Order. In April 2006, we and the DPS provided prefiled testimony as requested by the PSB. We are not able to predict the outcome of this matter at this time.

In March 2004, the PSB approved ENVY's request to increase generation at the Vermont Yankee plant by 110 megawatts. The PSB's approval included a condition that ENVY provide outage protection indemnification ("Ratepayer Protection Proposal" or "RPP") for times the uprate causes reductions in output that reduce the value of the PPA. Our maximum right to indemnification under the RPP is about $2.8 million for the three-year period beginning in May 2004 and ending after completion of the uprate (or a maximum of three years).

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On March 2, 2006, the Nuclear Regulatory Commission ("NRC") gave final approval to the uprate. Since that time Vermont Yankee plant output has slowly increased to the expected uprate level of 120 percent. Some time after completion of the uprate, the plant will receive a new output rating and our share of the plant's rating should be equivalent to the amount we received before the uprate process began. There is a risk that our percentage of energy output may decline if the plant needs to reduce output after the uprate. We estimate that this could have a material adverse effect on net power costs.

On March 16, 2006, we, Green Mountain Power, ENVY and the DPS filed a settlement with the PSB resolving all issues raised in a petition before the PSB regarding the RPP, including recovery of incremental replacement power costs associated with a June 2004 outage at the plant and reduced output due to the uprate. The settlement would resolve all issues through February 28, 2006. Our share of the settlement is estimated to be about $1.6 million including $0.7 million related to the June 2004 outage and the remaining for uprate-related costs. Pursuant to the Rate Order, any partial or full reimbursement received by us from ENVY under the RPP shall be recorded as a regulatory liability for return to ratepayers in our next rate proceeding. The settlement is not effective until the PSB issues a final order. We cannot predict the timing or outcome of this matter at this time.

ENVY had announced that it could be required to shut down the Vermont Yankee plant in 2007 or 2008 if dry cask storage of its nuclear waste (spent fuel) was not approved. In early June 2005, the Vermont State Legislature passed a law authorizing ENVY to construct and use dry cask storage facilities on the site through its current license, but required that Entergy return to the Legislature for permission to continue doing so past 2012, when its federal operating license expires. On April 26, 2006, the PSB issued its approval for dry cask storage for spent nuclear fuel through 2012.

If the Vermont Yankee plant is shut down for any reason prior to the end of its operating license, we would lose about 50 percent of our committed energy supply and would have to acquire replacement power resources comprising about 40 percent of our estimated power supply needs. Based on projected market prices, the incremental cost of lost power is estimated to average about $55 million on an annual basis. Based on this estimate, we would require a retail rate increase of about 20 percent for full cost recovery. We are not able to predict whether there will be an early shutdown of the Vermont Yankee plant or whether the PSB will allow timely and full recovery of increased costs related to any such shutdown. The implications of an early shut down of the Vermont Yankee plant could have a material effect on our financial position and future results of operations, if those costs are not recovered in retail rates in a timely fashion.

Independent Power Producers ("IPPs"): We purchase power from a number of IPPs that 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.

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. We also have a joint-ownership interest in Millstone Unit #3.

Maine Yankee, Connecticut Yankee and Yankee Atomic All three companies collect decommissioning and closure costs through FERC-approved wholesale rates charged under power agreements with several New England utilities, including us. Historically, our share of these costs has been recovered from retail customers through PSB-approved rates. We believe our share of decommissioning and closure costs for each plant will continue to be recovered through the regulatory process, but there is a risk that FERC may not allow full recovery of Connecticut Yankee's increased costs in wholesale rates, as described below.

Our share of Maine Yankee, Connecticut Yankee and Yankee Atomic estimated costs are reflected on the Condensed Consolidated Balance Sheets as regulatory assets and nuclear decommissioning liabilities (current and non-current). These amounts are adjusted when revised estimates are provided by the companies. At March 31, 2006, we had regulatory assets of about $4.5 million related to Maine Yankee, $9.7 million related to Connecticut Yankee and $4.5 million related to Yankee Atomic (including about $0.5 million for incremental decommissioning costs already paid by us that are now being recovered in retail rates pursuant to the Rate Order). These estimated costs are being collected from

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our customers through existing retail rate tariffs. Pursuant to the Rate Order, beginning April 1, 2006, we will defer any differences between actual decommissioning cost payments and amounts included for rate recovery, until our next rate proceeding.

Department of Energy ("DOE") Litigation: Maine Yankee, Connecticut Yankee and Yankee Atomic are seeking recovery of fuel storage-related costs stemming from the default of the DOE under the 1983 fuel disposal contracts that were mandated by the United States Congress under the Nuclear Waste Policy Act of 1982. Under the Act, the DOE was to begin removing spent nuclear fuel from the nuclear plants no later than January 1, 1998 in return for payments by each company into the nuclear waste fund. No fuel has been collected by the DOE, and spent nuclear fuel is being stored at each of the plants. Maine Yankee, Connecticut Yankee and Yankee Atomic collected the funds from wholesale utility customers, including us, under FERC-approved contract rates, and these payments were collected from our retail customers. All three are parties to a lawsuit against the DOE seeking damages based on the DOE's default.

On February 28, 2006, all three companies asked the Court to allow amended damage claim filings to cover the period ending December 31, 2002. The request was based on a September 2005 decision by the United States Court of Appeals for the Federal Circuit involving another nuclear utility's spent fuel that, among other things, found that plaintiffs in partial breach cases were not entitled to future damages. The proposed amended damage claims are about $79 million for Maine Yankee, $82.8 million for Connecticut Yankee and $101.8 million for Yankee Atomic. This compares to original claims of $160 million for Maine Yankee, $197.1 million for Connecticut Yankee and $191 million for Yankee Atomic. The original claims covered a longer expected period including future damages. Due to the complexity of the issues and the possibility of appeals, the three companies cannot predict the amount of damages to be received or the timing of the final determination of such damages. None of the companies have included a ny allowance for potential recovery of these claims in their FERC-filed cost estimates.

Maine Yankee: We have a 2 percent ownership interest in Maine Yankee. On October 3, 2005, Maine Yankee completed its decommissioning efforts and the NRC amended its operating license for operation of the Independent Spent Fuel Storage Installation.

Connecticut Yankee: We have a 2 percent ownership interest in Connecticut Yankee. Connecticut Yankee and Bechtel Power Corporation ("Bechtel") were engaged in litigation in Connecticut Superior Court concerning Connecticut Yankee's July 2003 termination of Bechtel's decommissioning contract for default and related disputes. On March 7, 2006, the parties settled their disputes. Bechtel agreed to pay Connecticut Yankee $15.0 million, release all claims and withdraw its intervention in the Company's FERC Rate Case. Connecticut Yankee agreed to release all claims and that the decommissioning contract be deemed terminated by agreement. Connecticut Yankee expects to credit net proceeds of the settlement against decommissioning costs recoverable under the power contracts with sponsor companies. At this time, we cannot predict the effect, if any, this settlement will have related to the FERC Rate Case described below. To the extent any amounts of the settlement payment are ultimately returned, these amounts will be credited for the future benefit of our retail ratepayers.

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. However, there is a risk, notwithstanding the ALJ Initial Decision, that some portion of the increased costs may not be recovered, or will have to be refunded if already recovered, as a result of the FERC proceedings. If FERC disallows cost recovery in wholesale

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rates, we anticipate that the PSB would disallow these costs for recovery in retail rates as well. The timing, amount and outcome of the FERC rate case filing cannot be predicted at this time.

Yankee Atomic: We have a 3.5 percent ownership interest in Yankee Atomic. The decommissioning effort is largely complete and final site-work is expected to conclude in 2006. Following the completion of decommissioning, the remaining on-site function will be to operate the Independent Spent Fuel Storage Installation. In November 2005, Yankee Atomic established an updated estimate of the cost of completing the decommissioning effort and submitted an application to FERC for increased decommissioning charges. Our share of the rate increase amounts to about $1.5 million for 2006 and $0.4 million annually for 2007 through 2010. On January 1, 2006, FERC issued an Order: 1) accepting Yankee Atomic's rate filing; 2) permitting the proposed rates to go into effect, subject to refund, as of February 1, 2006; and 3) referring the parties to a settlement judge to facilitate a possible settlement.

Millstone Unit #3 We have a 1.7303 percent joint ownership interest in Millstone Unit #3 and are responsible for our share of nuclear decommissioning costs. In January 2004, the lead owner Dominion Nuclear Corporation ("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. We continue to pay our share of the DOE Spent Fuel assessment expenses levied on actual generation and will share in recovery from the lawsuit, if any, in proportion to our ownership interest. On November 28, 2005, the NRC renewed the operating license for Millstone Unit #3 for an additional 20 years. T his extends the licensed life from November 2025 to November 2045.

DIVERSIFICATION
In the first quarter of 2006, CRC recorded net income of $0.4 million. This compares to $0.1 million for the same period in 2005. The $0.3 million increase is primarily related to interest income on the $59.25 million cash proceeds that CRC received from the Catamount sale.

RECENT ENERGY POLICY INITIATIVES
Energy initiatives in Vermont The State of Vermont continues to examine changes to the provision of electric service absent introduction of retail choice. The Vermont Legislature passed, in the concluded 2005 session, Act 61, "Renewable Energy, Efficiency, Transmission, and Vermont's Energy Future" ("Act 61"), a new law that includes two major provisions of interest to us:

Power Supply Requirements The new law establishes a Sustainably Priced Energy Enterprise Development ("SPEED") Program with a collective requirement of all Vermont retail electricity providers to, in aggregate, supply all of their incremental load growth between January 1, 2005 and January 1, 2012 from new renewable supplies, new Renewable Energy Certificates, or a combination of the two, capped at a total of 10 percent of the statewide kWh sales during calendar year 2005. The SPEED program begins on January 1, 2007. By July 1, 2013, the PSB must determine whether Vermont's retail electricity providers have met the SPEED program's requirements. If not met, the law states that the SPEED program's collective requirement reverts to a utility-specific renewable portfolio standard ("RPS").

Under either program, we could be required to purchase certain amounts of our energy supply requirement from new renewable sources while maintaining existing renewable power resources. Alternatively, if the utility-specific RPS

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takes effect, we may choose to pay an as-yet-undetermined charge per kWh, set by the PSB. The PSB is currently developing a rule to implement the SPEED program. The rule is expected to be finalized and adopted in September 2006.

Alternative Forms of Regulation Act 61 also allows the DPS and PSB to initiate proceedings to adopt 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. To date, neither we nor the regulators have sought to implement an alternate form of regulation for our operations.

The Vermont Legislature is currently in its 2006 session and legislation is expected to pass before adjournment that directs the PSB to expand the scope of net metering in Vermont. Net metering means measuring the difference between the electricity supplied to a customer and the electricity fed back by a metering system during the customer's billing period. Exactly how net metering is to be expanded is left to the PSB's discretion.

RECENT ACCOUNTING PRONOUNCEMENTS
On March 31, 2006, FASB issued an exposure draft that could 1) require recognition of the overfunded or underfunded positions of defined benefit postretirement plans on the balance sheet, and 2) require that plan assets and obligations be measured as of the balance sheet date. The proposed changes would be effective for fiscal years ending after December 15, 2006 for recognition of funded status on the balance sheet, and for fiscal years beginning after December 15, 2006 for measurement of plan assets and obligations as of the balance sheet date. We have not yet evaluated the impact of this exposure draft.

Also see Note 1 - Summary of Significant Accounting Policies to the accompanying Condensed Consolidated Financial Statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We consider our most significant market-related risks to be associated with wholesale power markets, equity markets and interest rates. Fair and adequate rate relief through cost-based-rate regulation can limit our exposure to market volatility. Except as discussed below, there were no material changes from the disclosures in our Annual Report on Form 10-K for the year ended December 31, 2005.

Wholesale Power Market Price 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, 2006 - unrealized loss Change in fair value, including amounts settled Fair value at March 31, 2006 - unrealized loss	$(12,935) 3,889 $(9,046)	$(4,977) 708 $(4,269)
Source	Over-the-counter-quotations	Quoted market data & valuation methodologies

Estimated fair value for changes in projected market price: 10 percent increase 10 percent decrease	$(11,729) $(6,363)	$(7,598) $(1,904)

Per a PSB-approved Accounting Order, changes in fair value of these derivatives are recorded as deferred charges or deferred credits on the balance sheet depending on whether the fair value is an unrealized loss or unrealized gain, with an offsetting amount recorded as a decrease or increase in the related derivative asset or liability.

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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. In the course of this evaluation, our management considered the material weakness in internal control identified as of December 31, 2005. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of March 31, 2006, our disclosure controls and procedures were not effective to ensure that the information required to be disclosed in our SEC reports is recorded, processed and summarized within the requisite time periods. In the first quarter of 2006, the Company implemented a policy of requiring confirmation from legal counsel that all filings with the SEC are in proper form (i.e., requiring legal "approval as to form").

To address the material weakness in internal control, we performed additional procedures to ensure our consolidated financial statements included in this interim report are fairly presented in all material respects in accordance with accounting principles generally accepted in the United States of America ("GAAP"). Accordingly, management believes that the financial statements included in this report fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented.

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 2006.

As discussed in Item 9A. Controls and Procedures in our Form 10-K as of December 31, 2005, there was a material weakness in our financial closing and reporting process. During 2006, we are taking the following actions to remediate the material weakness.

Formalize the process for identifying and documenting the accounting, reporting and tax implications for new, non-routine and non-recurring transactions.
Establish a process for documenting existing balance sheet accounts and key triggering events that might require reclassification. The quarterly account reconciliation process is also being enhanced for more timely reconciliations and review.
Implement a training plan within the Company's finance team with a focus on regulatory versus GAAP accounting requirements. The Company is also incorporating various control checklists into its control processes, including a comprehensive GAAP checklist.

Although we have taken some steps to implement our remediation plan, it has not been fully implemented as of the end of the first quarter of 2006. We will not be able to conclude that the material weakness has been successfully remediated until the testing of controls demonstrates that such controls have operated effectively for a sufficient period of time.

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PART II - OTHER INFORMATION
Item 1.		Legal Proceedings. The Company is involved in legal and administrative proceedings in the normal course of business and does not believe that the ultimate outcome of these proceedings will have a material adverse effect on its financial position or results of operations, except as otherwise disclosed herein.
Item 1A.		Risk Factors In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I "Item 1A. Risk Factors", in our Annual Report on Form 10-K for the year ended December 31, 2005, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds.
	The following table presents information with respect to purchase of Common Stock of the Company from January 2006 to April 2006.

Period	(a) Total Number of Shares (or Units) Purchased	(b) Average Price Paid per Share (or Units)	(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
January 2006 February 13, 2006 - April 5, 2006 March 2006 Total	0 2,249,975 0 2,249,975	0 $22.50 0 $22.50	0 Reverse Dutch Auction Buyback 0	0 0 0 0
On February 7, 2006, we publicly announced a reverse Dutch Auction buyback of up to 2,250,000 shares of our Company's Common Stock. The tender offer commenced on February 13, 2006 and was to expire on March 15, 2006. On March 14, 2006, Central Vermont announced it would extend the offer to purchase until April 5, 2006. On April 19, 2006 the Company completed the repurchase of shares.

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Item 4.	Submission of Matters to a Vote of Security Holders.
	(a) The Registrant held its Annual Meeting of Stockholders on May 2, 2006.
	(b) Director elected whose term will expire in year 2007:
					Votes FOR	Votes WITHHELD
	William J. Stenger				10,179,946	151,310
	Directors elected whose term will expire in year 2009:
					Votes FOR	Votes WITHHELD
	Robert L. Barnett Robert G. Clarke Mary Alice McKenzie William R. Sayre				10,190,377 9,387,708 10,196,297 10,180,520	140,779 943,448 134,859 150,636
	Other Directors whose terms will expire in 2007:
	Bruce M. Lisman Janice L. Scites
	Other Directors whose terms will expire in 2008:
	Rhonda L. Brooks Janice B. Case Robert H. Young
	(c) Ratification of the appointment of Deloitte & Touche LLP as independent registered public accountants for fiscal year ending December 31, 2006.
	For Against Abstain			9,524,778 761,375 45,003

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.
Page 42 of 44 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/ Edmund F. Ryan
	Edmund F. Ryan Acting Chief Financial Officer, and Treasurer

Dated May 10, 2006

Page 43 of 44

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

Page 44 of 44

EX-31 3 ex31_1.htm EXHIBIT 31.1 CEO SECTION 302 CERTIFICATION EXHIBIT 31.1

EXHIBIT 31.1 ANNUAL CERTIFICATION OF CHIEF EXECUTIVE OFFICER REQUIRED BY SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Robert H. Young, certify that:
1.	I have reviewed this quarterly report on Form 10-Q of Central Vermont Public Service Corporation (the "registrant");
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
	a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: May 10, 2006 /s/ Robert H. Young Robert H. Young Chief Executive Officer

EX-31 4 ex31_2.htm EXHIBIT 31.2 CFO SECTION 302 CERTIFICATION EXHIBIT 31.2

EXHIBIT 31.2 ANNUAL CERTIFICATION OF CHIEF EXECUTIVE OFFICER REQUIRED BY SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Edmund F. Ryan, certify that:
1.	I have reviewed this quarterly report on Form 10-Q of Central Vermont Public Service Corporation (the "registrant");
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
	a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: May 10, 2006 /s/ Edmund F. Ryan Edmund F. Ryan Acting Chief Financial Officer

EX-32 5 ex32_1.htm EXHIBIT 32.1 CEO SECTION 906 CERTIFICATION EXHIBIT 32.1

EXHIBIT 32.1

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

In connection with the Quarterly Report of Central Vermont Public Service Corporation (the "Company") on Form 10-Q for the period ended March 31, 2006 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, 2006

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 6 ex32_2.htm EXHIBIT 32.2 CFO SECTION 906 CERTIFICATION EXHIBIT 32.2

EXHIBIT 32.2

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

In connection with the Quarterly Report of Central Vermont Public Service Corporation (the "Company") on Form 10-Q for the period ended March 31, 2006 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I Edmund F. Ryan, Acting 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/ Edmund F. Ryan
Edmund F. Ryan
Acting Chief Financial Officer
May 10, 2006

-----END PRIVACY-ENHANCED MESSAGE-----

	Three months ended March 31, 2006 2005
Interest on temporary investments Non-utility revenue and non-operating rental income Amortization of contributions in aid of construction Other interest and dividends Regulatory asset carrying costs* Miscellaneous other income Total	$890 473 218 159 - - 413 $2,153	$340 483 210 91 (653) 4 $475
*For 2005, includes $(822) of Rate Order-related adjustments.

	Three months ended March 31, 2006 2005
Supplemental retirement benefits and insurance Non-utility expenses Realized losses on available-for-sale securities Vermont Yankee fuel rod disallowance - Rate Order Miscellaneous other deductions Total	$161 324 - - - - 236 $721	$252 277 573 403 180 $1,685

	Three months ended March 31, 2006 2005
Numerator for basic and diluted EPS: Net income (loss) from continuing operations: Income (loss) from continuing operations Dividends declared on preferred stock Net income (loss) from continuing operations available for common stock Denominators for basic and diluted EPS: Average shares of common stock outstanding - basic Dilutive effect of stock options Dilutive effect of unvested and performance shares Average shares of common stock outstanding - diluted	$4,097 (92) $4,005 12,297,528 63,673 2,730 12,363,931	$(4,915) (92) $(5,007) 12,219,130 - - - 12,219,130

	Three months ended March 31, 2006 2005
Cash paid during the year for: Interest (net of amounts capitalized) Income taxes (net of refunds)	$173 $25	$89 $34

	Three months ended March 31, 2006 2005
Operating revenues Operating income Net income Company's ownership interest: 58.85% Company's equity in net income	$44,347 $776 $173 $102	$42,349 $56 $162 $95

	Three months ended March 31, 2006 2005
Operating revenues Operating income Net income Company's ownership interest: Common stock Preferred stock Company's equity in net income	$8,987 $2,214 $771 47.05% 48.03% $391	$7,982 $2,091 $730 47.02% 48.03% $365

	Three months ended March 31, 2006 2005
Operating revenues Operating expenses Operating Income Other income and (deductions): Equity in earnings of non-utility investments Other income Other deductions Benefit for income taxes Total other income and (deductions) Total operating and other income Total interest expense Net income from discontinued operations	$- - - - - - - - - - - - - - $-	$- (99) 99 932 1,183 (1,814) (38) 263 362 74 $288

	Fair value of debt securities at contractual maturity dates
Debt Securities	Less than 1 year $12,942	1 to 5 years $3,918	5 to 10 years -	After 10 years $19,525	Total $36,385

	Fair value of debt securities at contractual maturity dates
Debt Securities	Less than 1 year $31	1 to 5 years $360	5 to 10 years $242	After 10 years $688	Total $1,321

	Equity Securities		Debt Securities
	Fair Value	Unrealized Losses	Fair Value	Unrealized Losses
Less than 12 months 12 months or more Total	$2 135 $137	- $10 $10	$650 124 $774	$10 4 $14