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     June 30, 2006    

or

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

For the transition period from _______ to _______

Commission file number     1-8222   

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

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

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

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

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

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

     Indicate by check mark whether the registrant is 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 July 31, 2006 there were outstanding 10,091,097 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    and six months ended June 30, 2006 and 2005	3
	Condensed Consolidated Statements of Comprehensive Income (Loss) (unaudited) for the    three and six months ended June 30, 2006 and 2005	4
	Condensed Consolidated Statements of Cash Flows (unaudited) for the    six months ended June 30, 2006 and 2005	5
	Condensed Consolidated Balance Sheets as of June 30, 2006 (unaudited) and    December 31, 2005	6
	Condensed Consolidated Statement of Changes in Common Stock Equity (unaudited)    for the six months ended June 30, 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	31
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	48
Item 4.	Controls and Procedures	48
PART II	OTHER INFORMATION	50
SIGNATURES		51
EXHIBIT INDEX		52

Page 2 of 52

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS) (in thousands, except share data) (unaudited)
	Three Months Ended		Six Months Ended
	June 30		June 30
	2006	2005	2006	2005
Operating Revenues	$78,992	$75,116	$161,247	$150,780
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	21,050  21,933  2,339  809  4,192  13,095  5,331  4,129  3,628     248   76,754	15,671  22,794  2,243  1,077  3,070  11,792  4,713  4,090  3,329     2,680   71,459	37,860  47,611  5,192  2,152  7,644  25,658  10,846  8,220  7,244     1,962   154,389	31,660  48,652  5,014  1,991  6,579  34,345  8,319  8,155  6,935     (3,539)  148,111
Operating Income	2,238	3,657	6,858	2,669
Other Income and (Deductions)   Equity in earnings of affiliates   Allowance for equity funds during construction   Other income   Other deductions   Provision for income taxes   Total Other Income	352  40  1,295  (743)       (144)     800	478  19  1,241  (565)       (112)     1,061	869  63  3,448  (1,464)       (597)     2,319	961  32  1,716  (2,250)       (68)     391
Total Operating and Other Income	3,038	4,718	9,177	3,060
Interest Expense   Interest on long-term debt   Other interest   Allowance for borrowed funds during construction Total Interest Expense	1,799  257         (13) 2,043	1,799  291         (6) 2,084	3,598  508         (21) 4,085	3,598  1,753         (10) 5,341
Income (loss) from continuing operations Loss from discontinued operations, net of income tax Net Income (Loss) Dividends declared on preferred stock	995       -  995         92	2,634       (544) 2,090         92	5,092       -  5,092         184	(2,281)      (256) (2,537)        184
Earnings (loss) available for common stock	$903	$1,998	$4,908	$(2,721)
Per Common Share Data: Basic:   Earnings (loss) from continuing operations   Loss from discontinued operations   Earnings (loss) per share Diluted:   Earnings (loss) from continuing operations   Loss from discontinued operations   Earnings (loss) per share	$0.08          -  $0.08  $0.08           -  $0.08	$.21     (.04) $.17  $.21     (.04) $.17	$0.43          -  $0.43  $0.43           -  $0.43	$(.20)    (.02) $(.22) $(.20)    (.02) $(.22)
Average shares of common stock outstanding - basic Average shares of common stock outstanding - diluted Dividends declared per share of common stock	10,634,854  10,682,809  $.46	12,259,428  12,393,181  $.23	11,403,213  11,460,706  $.46	12,239,390  12,239,390  $.69

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

Page 3 of 52

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (in thousands) (unaudited)
	Three Months Ended June 30		Six Months Ended June 30
	2006	2005	2006	2005
Net Income (loss)	$995	$2,090	$5,092	$(2,537)
Other comprehensive income (loss), net of tax: Investments:   Unrealized holding gain        net of taxes of $4, $53, $26 and $6   Realized (gain) loss       net of taxes of $(7), $0, $(24), $114 Foreign currency    Other comprehensive income from discontinued operations,       net of taxes of $0, $32, $0 and $39	5  (12)           -         (7)	79 -         48      127	38  (37)          -            1	10  166          58        234
Comprehensive Income (loss)	$988	$2,217	$5,093	$(2,303)

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

Page 4 of 52

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)
	Six Months Ended June 30,
	2006	2005
Cash flows provided (used) by: OPERATING ACTIVITIES Net income Deduct: Loss 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 2005 Rate Order Non-cash employee benefit plan costs      (Gains) 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 (increase) in accounts receivable and unbilled revenues            Decrease in accounts payable            Increase (decrease) in accrued income taxes            (Decrease) increase in other current assets            Decrease (increase) in special deposits            Decrease in other current liabilities            Employee benefit plan funding and related payments            Other non-current assets and liabilities and other Net cash provided by operating activities of continuing operations	$5,092           -  5,092  (869) 880  8,220  (723) 141  - 5,220  (42) 568  (300) 5,060  (1,231) 1,512  (833) 9,397  (472) (17,582)     670     14,708	$(2,537)      256  (2,281) (961) 989  8,155  2,555  (6,283) 21,846  3,973  718  (119) -  (151) (7,123) (1,550) 2,181  (4,445) (1,613) (1,062)    (199)  14,630
INVESTING ACTIVITIES      Construction and plant expenditures     Investments in available-for-sale securities      Proceeds from sale of available-for-sale securities      Investment in affiliates      Investment in discontinued operations      Note receivable repayment from discontinued operations      Bridge loan to 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	(9,531) (245,406) 311,689  (8,886) -  -  -  (309) (2,021) 334  103       (113)    45,860	(7,321) (131,200) 135,800  -  (5,900) 11,000  (12,800) -  (422) 408  70          49   (10,316)
FINANCING ACTIVITIES      Proceeds from issuance of common stock      Common and preferred dividends paid      Treasury stock acquisition - tender offer      Proceeds from borrowings under revolving credit facility      Repayments under revolving credit facility      Reduction in capital lease obligations      Other Net cash used for financing activities of continuing operations	675  (5,496)     (51,172) 300  (300) (510)            49    (56,454)	1,117   (6,058) -  -  -  (505)         (4) (5,450)
DISCONTINUED OPERATIONS        Net cash provided by operating activities      Net cash used for investing activities      Net cash provided by financing activities Net cash provided by discontinued operations	-  -    -    -	3,513   (10,748)  7,700    465
Net increase (decrease) in cash and cash equivalents Cash and cash equivalents at beginning of the period Cash and cash equivalents at end of the period	4,114      6,576  $10,690	(671)  11,722* $11,051*

*Assets of discontinued operations included cash of $3.0 million at June 30, 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 52

CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands, except share data)
	(unaudited)                                 June 30,             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	$520,147   228,150 291,997 7,862      1,052  300,911	$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	24,430 2,004 4,968 1,000       6,405     38,807	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       ($2,990 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	10,690 10,615 2,905 9,696 19,782 228 14,728 5,278 7,034 3,408         702    85,066	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	24,959 15,613       6,763     47,335 $472,119	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 52
CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands, except share data)
	(unaudited)                                June 30,             December 31,         2006                           2005
CAPITALIZATION AND LIABILITIES Capitalization   Common stock, $6 par value, 19,000,000 shares authorized, 12,341,072      shares issued and 10,091,097 shares outstanding at June 30, 2006,      12,283,405 shares issued and outstanding at December 31, 2005   Other paid-in capital   Accumulated other comprehensive loss   Deferred compensation - employee stock ownership plans   Treasury stock, at cost (2,249,975 shares and 0, respectively)   Retained earnings Total common stock equity   Preferred and preference stock   Preferred stock with sinking fund requirements   Long-term debt   Capital lease obligations Total capitalization	$74,008  53,479  (413) -  (51,172)   91,846  167,748  8,054  3,000  115,950      5,805  300,557		$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  3,399  12,918  10,800  1,182  342  2,321  4,419  2,709     19,403    58,493		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	29,163  3,909  12,806  3,966  13,075  9,279  13,132     27,739   113,069  $472,119		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 52

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN COMMON STOCK EQUITY (unaudited)
	Shares		(in thousands)
Six months ended June 30,    2005 and 2006	Common	Treasury	Common Stock	Other Paid-in Capital	Accum OCI	Deferred Comp.	Treasury Stock	Retained Earnings	Total
Balance, December 31, 2004 Net loss Other Comprehensive Income ("OCI") Stock options exercised Dividend reinvestment plan Amortization of share-based    compensation Allocation of benefits - performance    share plan Dividends declared on capital stock:    Common - $.23 per share    Cumulative non-redeemable preferred Amortization of preferred stock    issuance expenses Balance, June 30, 2005	12,193,093 17,400 39,434 4,770 19,920                    12,274,617	-                                  -	$73,153 104 236 29 120               $73,642	$51,964  198  629  (50) (430)          15  $52,326	$(130) 234            $104	$(36) 21               $(15)	$-                  $          -	$99,702  (2,537) (8,448) (184)                $88,533	$224,653  (2,537) 234  302  865  -  (310) (8,448) (184)         15  $214,590
Balance, December 31, 2005 Net income Other Comprehensive Income ("OCI") Common stock reacquired Stock options exercised Amortization of share-based    compensation Dividends declared on capital stock:    Common - $.23 per share    Cumulative non-redeemable preferred Amortization of preferred stock    issuance expenses Balance, June 30, 2006	12,283,405 46,110 11,557                    12,341,072	-  2,249,975                   2,249,975	$73,695 277  36                $74,008	$52,513 482  445           39 $53,479	$(414) 1               $(413)	$(5) 5               $-	$-  (51,172)                 $(51,172)	$91,581  5,092  (4,643) (184)                  $91,846	$217,370  5,092  1  (51,172) 759  486  (4,643) (184)          39  $167,748

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

Page 8 of 52

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, 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 sold 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. Operating results for the three and six months ended June 30, 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 footnotes 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 Statement of Financial Accounting Standards ("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 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 the Company's 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 $27.4 million on a pre-tax basis as of June 30, 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.

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

	June 30, 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	$2,533 3,462 3,625 1,932 1,969 1,196 861 779     3,046 $19,403	$2,569 3,253 3,016 3,021 1,257 1,196 1,167 941     3,828 $20,248

Page 9 of 52

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

	June 30, 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	$4,505 7,990 4,836 10,165       243 $27,739	$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 June 30, 2006                  2005		Six Months Ended June 30, 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* Gain of sale of non-utility property Miscellaneous other income Total	$374  467  220  170  -  -        64  $1,295	$366  483  208  168  -  12        4  $1,241	$1,264  940  438  329  -  317        160  $3,448	$706  966  418  259  (653) 12        8  $1,716
*For six months ended June 30, 2005 includes $(822) of 2005 Rate Order-related adjustments.

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

	Three Months Ended June 30, 2006                  2005		Six Months Ended June 30, 2006                  2005
Supplemental retirement benefits and insurance Non-utility expenses Realized losses on available-for-sale securities Vermont Yankee fuel rod disallowance - 2005 Rate Order Miscellaneous other deductions Total	$316 299 -  -    128 $743	$173  300  -  -       92  $565	$477 623 -  -    364 $1,464	$425  577  573  403       272  $2,250

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	June 30, 2006
Unrealized loss on investments Non-qualified benefit obligations Accumulated other comprehensive income (loss)	$(20) (394) $(414)	$1    -  $1	$(19) (394) $(413)

Share-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 No. 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 instruments issued. SFAS No. 123R also requires that 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 is unchanged.

Page 10 of 52

Prior to adoption of SFAS No. 123R, the Company accounted for its share-based compensation plans under APB No. 25 and related guidance. Additionally, the Company complied with the disclosure provisions of SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of SFAS No. 123. Accordingly, no compensation expense was recognized for stock options granted in periods prior to January 1, 2006. Compensation expense related to the grant of common shares and restricted stock, excluding those with performance measures, was based on the market value of the Company's underlying common stock on the date of grant and was recognized over the vest period. Compensation expense for restricted stock in the form of performance shares was recognized over the three-year performance cycles and was adjusted quarterly based on actual performance versus internal performance measures, changes in the market value of the Company's common stock, and the Company's total shareholder return versus a comparison group. Prior to adoption, the Company recognized compensation costs for all share-based compensation over the nominal (stated) vesting period. For awards granted after adoption of SFAS No. 123R, compensation costs are now recognized over the shorter of the nominal vesting period or the period until the employee's award becomes non-forfeitable upon reaching retirement age under the terms of the award.

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 share-based compensation plans are described in more detail in Note 7 - Share-Based Compensation Plans.

The Company recorded pre-tax compensation expense of $0.4 million for all share-based compensation in the second quarter and $0.5 million in the first half of 2006, and tax benefits of $0.2 million for the second quarter and first half of 2006. For stock options, the Company receives an income tax deduction equal to the excess of the market value of its common stock on the date of exercise over the stock option exercise prices. For the first half of 2006, excess tax benefits of about $0.1 million are included in Other in Financing Activities on the Condensed Consolidated Statement of Cash Flows. The Company recorded pre-tax compensation expense of $0.1 million for all share-based compensation for the second quarter and a nominal amount for the first half of 2005, and tax benefits of a nominal amount in the second quarter and first half of 2005.

If share-based compensation expense for the second quarter and first half of 2005 had been determined and recorded based on the fair value method prescribed prior to adoption of SFAS No. 123R, the Company's net income and earnings per share would have been as follows (in thousands, except per share amounts).

	June 30, 2005
	Three Months Ended	Six Months Ended
Earnings (loss) available for common stock, as reported	$1,998	$(2,721)
Add: Share-based compensation expense included in    reported net income, net of tax	64	-
Deduct: Share-based compensation expense under fair value    method, net of tax	194	130
Pro forma net income	$1,868	$(2,851)
Earnings (loss) per share:
Basic - as reported	$0.17	$(.22)
Basic - pro forma	$0.16	$(.23)
Diluted - as reported	$0.17	$(.22)
Diluted - pro forma	$0.16	$(.23)

Page 11 of 52

Earnings Per Share ("EPS") The Condensed Consolidated Statements of Income include basic and diluted per share information. In the second quarter of 2006, the Company purchased 2,249,975 shares of its common stock as described in Note 6 - Treasury Stock. 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 the numerator and denominator used in calculating basic and diluted EPS (in thousands, except share information):

	Three Months Ended June 30, 2006                  2005		Six Months Ended June 30, 2006                  2005
Numerator for basic and diluted EPS:    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: Weighted-average basic shares of common stock outstanding    Dilutive effect of stock options    Dilutive effect of nonvested and performance shares Weighted-average diluted shares of common stock outstanding	$995       (92) $903  10,634,854  42,473          5,482  10,682,809	$2,634         (92) $2,542  12,259,428  127,861           5,892  12,393,181	$5,092       (184) $4,908  11,403,213  51,970          5,523  11,460,706	$(2,281)        (184) $(2,465) 12,239,390  -                  -  12,239,390

Outstanding stock options totaling 259,417 in the second quarter of 2006 and 198,017 in the first half of 2006 were excluded from the computation of diluted shares because the exercise prices were above the average market price of the common shares. For the second quarter of 2005, 73,071 stock options were excluded from the computation of diluted shares because the exercise prices were above the average market price of the common shares. There were no potentially dilutive shares in the first half of 2005 since the Company incurred a loss for the period.

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.

Restricted Cash The Company held restricted cash of $2.9 million at June 30, 2006 and $0.9 million at December 31, 2005. The balance in both periods included $0.9 million related to property release requirements under the first mortgage indenture. Restricted cash at June 30, 2006 also included collateral payments of $2.0 million related to performance assurance requirements for power transactions through ISO-New England described in Note 9 - Commitments and Contingencies.

Special Deposits The Company had special deposits of $9.7 million at June 30, 2006 and $21.1 million at December 31, 2005. The balance in both periods included collateral payments related to performance assurance requirements for certain of the Company's power contracts described in Note 9 - Commitments and Contingencies. Special deposits at December 31, 2005 also included $2.0 million for mandatory redeemable preferred stock. The payment to preferred shareholders was made effective January 1, 2006 and included $1.0 million for a mandatory sinking fund payment and $1.0 million for an optional sinking fund payment.

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

	Six Months Ended June 30, 2006                 2005
Cash paid during the year for:    Interest (net of amounts capitalized)    Income taxes (net of refunds)	$3,908 $1,956	$3,721 $2,869

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

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Non-cash Operating, Investing and Financing Activities Construction and plant expenditures on the Condensed Consolidated Statements of Cash Flows reflect actual payments made during the periods. The Company accrues for construction and plant-related expenditures at the end of each reporting period. At June 30, 2006, less than $0.1 million of construction and plant-related accruals was included in Accounts Payable, and about $0.1 million was included in Other Current Liabilities. At December 31, 2005, about $1.0 million of construction and plant-related accruals was included in Accounts Payable and about $0.5 million was included in Other Current Liabilities. Other non-cash activities are described in Note 3 - Retail Rates and Regulatory Accounting, and Note 9 - 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.

Reclassifications The Company has reclassified $2.9 million from Other non-current assets and liabilities and other on the 2005 Condensed Consolidated Statement of Cash Flows, to conform to the 2006 presentation. Of this amount, $4.0 million is reported as Non-cash employee benefit plan costs, and $1.1 million is reported as Employee benefit plan funding and related payments.

Recent Accounting Pronouncements

SFAS No. 123R: See Share-Based Compensation above.

FSP No. FIN 46R-6: In April 2006, FASB issued Staff Position No. FIN 46R-6, Determining the Variability to Be Considered in Applying FASB Interpretation No. 46R ("FSP No. 46R-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 ("FIN 46R"), which could impact the assessment of whether certain variable interest entities are consolidated. FSP No. 46R-6 is effective 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.

FIN 48: In June 2006, FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109 ("FIN 48"), which clarifies the accounting for uncertainty in income taxes recognized in accordance with FASB Statement No. 109, Accounting for Income Taxes ("SFAS No. 109"). FIN 48 defines criteria that an individual tax position must meet for any part of the benefit of that position to be recognized in the financial statements. Additionally, FIN 48 provides guidance on the measurement, derecognition, classification and disclosure of tax positions, along with accounting for the related interest and penalties. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. The Company is currently evaluating the impact that FIN 48 will have on its financial position, results of operations and cash flows.

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NOTE 2 - INVESTMENTS IN AFFILIATES

The Company's equity method investments are as follows (in thousands):

	Ownership	June 30, 2006	December 31, 2005
Vermont Yankee Nuclear Power Corporation Vermont Electric Power Company, Inc.:    Common stock    Preferred stock      Subtotal Vermont Transco LLC (a) Nuclear generating companies:    Connecticut Yankee Atomic Power Company    Maine Yankee Atomic Power Company    Yankee Atomic Electric Company      Subtotal Total Investment in Affiliates	58.85% 47.05% 48.03% 20.1% 2.00% 2.00% 3.50%	$2,814 11,299      209 11,508 8,886 $844 344       34 1,222 $24,430	$2,802  11,260       202  11,462  -  $936  565    36  1,537  $15,801
(a) Vermont Transco LLC was formed by Vermont Electric Power Company, Inc and its owners in the second       quarter of 2006 as described below.

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

	Three Months Ended June 30,		Six Months Ended June 30,
	2006	2005	2006	2005
Operating revenues Operating income (loss) Net income Company's equity in net income	$56,013  $993  $168  $99	$40,960  $(1,403) $180  $106	$100,360 $1,769 $341 $201	$83,309  $(1,347) $342  $201

The Company received $0.1 million of cash dividends from VYNPC in the second quarter of 2006 and 2005, and $0.2 million in the first half of 2006 and 2005. VYNPC's revenues shown in the table above include sales to the Company of $19.6 million for the second quarter and $35.1 million for the first half of 2006, and $14.3 million for the second quarter and $29.2 million for the first half of 2005. These amounts, offset by deferral of nuclear insurance refunds and sale of a small percentage of our entitlement to a secondary purchaser, are included in Purchased power - affiliates on the Company's Condensed Consolidated Statements of Income. Accounts payable to VYNPC amounted to $6.8 million at June 30, 2006 and $5.4 million at December 31, 2005.

Vermont Electric Power Company, Inc ("VELCO") and Vermont Transco LLC ("Transco") In June 2006, VELCO's Board of Directors, the PSB and the FERC approved a plan to transfer substantially all of VELCO's business operations to Transco, a Vermont limited liability company formed by VELCO and its owners, including the Company. On June 30, 2006, VELCO's assets were transferred to Transco in exchange for 2.4 million Class A Units, and Transco assumed all of VELCO's debt. VELCO and its employees will manage the operations of Transco under a Management Agreement between VELCO and Transco. Transco will operate under an Operating Agreement among VELCO, Transco, the Company, Green Mountain Power and most of the other Vermont electric utilities. Transco will also operate under the Amended and Restated Three Party Agreements, assigned to Transco from VELCO, among the Company, Green Mountain Power, VELCO and Transco. VELCO has a 54.2 percent ownership interest in Transco, which results in a 25.5 percent indirect interest for the Company.

On June 30, 2006, the Company invested $8.9 million in Transco and received a 20.1 percent equity ownership interest in Transco represented by Class A Units that have an allowed rate of return of 11.5 percent. The Company's total direct and indirect interest in Transco is 45.6 percent. In addition to the Company's and Velco's investments in Transco, most of Velco's other owners also invested a total of $11.4 million, representing the remaining 25.7 percent ownership in Transco.

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In the second quarter of 2006, the Company reassessed its ownership interest in VELCO under the provisions of FIN 46R, and concluded that VELCO is not a variable interest entity ("VIE"). The Company also assessed its ownership interest in Transco and concluded that Transco is not a VIE.

VELCO's summarized financial information shown in the tables below is presented on a consolidated basis and therefore includes the assets and liabilities of Transco (in thousands):

	Three Months Ended June 30,			Six Months Ended June 30,
	2006		2005	2006		2005
Operating revenues Operating income Net income Company's equity in net income	$8,469  $2,365  $731  $352		$7,524  $2,049  $743  $347	$17,456  $4,579  $1,502  $743		$15,506  $4,140  $1,473  $712
		June 30, 2006			December 31, 2005
Investment Current assets Non-current assets Total assets Less:     Current liabilities     Non-current liabilities Net assets Company's equity in net assets		$44,354 196,071 240,425 96,086   99,608 $44,731 $20,394			$26,044 161,504 187,548 93,397  69,745  $24,406 $11,462

Included in VELCO's revenues above are billings to the Company of $1.2 million for the second quarter and $2.8 million for the first half of 2006, and $1.1 million for the second quarter and $2.1 million for the first half of 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 $5.9 million at June 30, 2006 and December 31, 2005.

The Company received $0.3 million of cash dividends from VELCO in the second quarter and $0.7 million the first half of 2006, which included less than $0.1 million related to return of capital from VELCO's Class C preferred stock. In the second quarter of 2005, the Company received $0.4 million in cash dividends from VELCO and $0.8 million in the first half of 2005, which included less than $0.1 million related to return of capital from VELCO's Class C preferred stock.

The Company did not receive any cash distributions or equity in net income from Transco in the second quarter of 2006. Transco's summarized financial information, also included in VELCO's consolidated financial information above, follows (in thousands):

	June 30, 2006	December 31, 2005
Investment Current assets Non-current assets Total assets Less:     Current liabilities     Non-current liabilities Net assets Company's equity in net assets	$31,360 191,812 223,172 83,169   95,711 $44,292 $8,886	$ -      -  -  -       -    $ -  $ -

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Maine Yankee, Connecticut Yankee and Yankee Atomic

The Company has equity ownership interests in three nuclear plants, consisting of 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 $1.5 million for the second quarter and $2.9 million for the first half of 2006, and $1.4 million for the second quarter and $2.6 million for the first half of 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 9 - Commitments and Contingencies.

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 ("2005 Rate Order") that 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 2005 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 2005 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 described 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 focused on whether the 2005 Rate Order set rates retroactively without statutory authorization. On July 27, 2005, the Vermont Department of Public Service ("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. See Note 12 - Subsequent Events for additional information.

On May 15, 2006, the Company filed a request for a 6.15 percent rate increase (additional revenue of about $16. 4 million on an annual basis), to be effective February 1, 2007.  The case is proceeding pursuant to an agreed-upon schedule, and a decision is expected in late January 2007.  The Company cannot predict the outcome of this rate proceeding at this time.

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 2005 Rate Order. In the 2005 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)
	June 30, 2006	December 31, 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	$17,613 923 3,786 1,489 693 401           54    24,959	$20,995 1,538 3,810 2,481 1,154 384           82    30,444
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Other deferred charges - regulatory Vermont Yankee sale costs (tax) Unrealized loss on power contract derivatives Nuclear decommissioning costs above amounts in retail rates Tree trimming and pole treating     Subtotal Other deferred charges - regulatory	3,130 11,987 243        253   15,613	3,130 17,912 -              3    21,045
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	6,725 1,662 1,513 1,088 855        1,289   13,132	8,646 2,770 1,337 1,088 481      1,102   15,424
Net regulatory assets, deferred charges and deferred credits	$27,440	$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 June 30, 2006                  2005		Six Months Ended June 30, 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 (deductions) Total interest expense Net loss from discontinued operations	$-    -    -  -  -  -    -    -  -    -  $-	$-  (93) 93  427  431  (1,438)     73     (507) (414)    130  $(544)	$-    -    -  -  -  -    -    -  -    -  $-	$-  (192) 192  1,359  1,614  (3,252)     35     (244) (52)    204  $(256)

See Note 9 - Commitments and Contingencies for Catamount indemnifications.

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.

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The Company recorded $0.1 million of realized gains on available-for-sale securities, nominal debt security premium amortizations, and a nominal amount of realized losses in the second quarter and first half of 2006. The Company recorded nominal amounts of realized losses and premium amortizations in the second quarter of 2005 and $0.1 million of realized losses and $0.3 million of debt security premium amortizations in the first half of 2005.

In the second quarter of 2006, an impairment of a nominal amount was included in realized losses for a security that is now expected to be redeemed prior to maturity. The Company previously recorded an impairment of $0.3 million in the first quarter of 2005.

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 follows (in thousands):

	June 30, 2006				December 31, 2005
Security Types	Amortized Cost	Unrealized Gains	Unrealized Losses	Estimated Fair Value	Amortized Cost	Unrealized Gains	Unrealized Losses	Estimated Fair Value
Current Assets:      Debt Securities:         US Government Agencies      Corporate Bonds      Auction Rate Securities       Subtotal      Equity Securities:      Auction Rate Securities      Subtotal Investments and Other Assets:      Debt Securities:      US Government Agencies      Corporate Bonds      Subtotal Total	$6,408 1,488    2,100    9,996       650    10,646 1,000            -      1,000 $11,646	$10 10         -     20     -     20 -      -      -  $20	$(51) -       -    (51)      -  (51) -        -        -  $(51)	$6,367 1,498  2,100  9,965           650  10,615 1,000           -      1,000 $11,615	$12,355 4,732   27,100   44,187   28,200   72,387 3,973     1,504     5,477 $77,864	$82  29         -   111       -   111  1       3       4  $115	$(47)  (19)         -    (66)         -    (66)  (31)        -     (31)  $(97)	$12,390 4,742    27,100   44,232   28,200   72,432 3,943     1,507     5,450 $77,882

Information related to the fair value of debt securities at June 30, 2006 follows (in thousands):

	Fair value of debt securities at contractual maturity dates
Debt Securities	Less than 1 year $4,962	1 to 5 years $3,903	5 to 10 years -	After 10 years $2,100	Total $10,965

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 June 30, 2006 (in thousands):

	Debt Securities
	Fair Value	Unrealized Losses
Less than 12 months (2 securities) 12 months or more (2 securities)      Total	$3,903   1,482 $5,385	$(35)   (16) $(51)

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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):

	June 30, 2006				December 31, 2005
Security Types	Amortized Cost	Unrealized Gains	Unrealized Losses	Estimated Fair Value	Amortized Cost	Unrealized Gains	Unrealized Losses		Estimated Fair Value
Equity Securities Debt Securities Cash and other      Total	$2,447 1,294           50 $3,791	$1,212 8         -  $1,220	$(12) (31)           - $(43)	$3,647 1,271         50 $4,968	$2,415 1,283           42 $3,740	$1,151 22         -  $1,173	$(15) (13)         - $(28)	$3,551 1,292        42 $4,885

Information related to the fair value of debt securities at June 30, 2006 follows (in thousands):

	Fair value of debt securities at contractual maturity dates
Debt Securities	Less than 1 year $13	1 to 5 years $306	5 to 10 years $255	After 10 years $697	Total $1,271

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 June 30, 2006 (in thousands):

	Equity Securities		Debt Securities
	Fair Value	Unrealized Losses	Fair Value	Unrealized Losses
Less than 12 months 12 months or more      Total	$30   121 $151	$(2)   (10) $(12)	$886   113 $999	$(25)     (6) $(31)

NOTE 6 - TREASURY STOCK
On February 7, 2006, the Company announced that its Board of Directors approved using approximately $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, which represented about 18.3 percent of the Company's outstanding common stock. In April 2006, the Company purchased 2,249,975 shares at $22.50 per share of common stock.

NOTE 7 - SHARE-BASED COMPENSATION PLANS

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.

Share-based compensation to executive officers and non-employee directors has included a combination of common shares, stock options and restricted stock that cliff vests based on service conditions, or performance measures (referred to as performance shares). Restricted stock granted under the Company's share-based compensation plans are referred to as nonvested shares under SFAS No. 123R since there are no restrictions after the shares vest.

Stock options have been granted to executive officers and non-employee directors under several stock option plans, including the 1997 Stock Option Plan for Key Employees, the 2000 Plan for Key Employees, the 1998 Stock Option Plan for Non-Employee Directors, and the 2002 Long-Term Incentive Plan ("2002 LTIP"), which also authorizes the granting of stock appreciation rights, restricted shares and performance shares. Restricted stock with service conditions have been granted to executive officers under the 2002 LTIP and the 1997 Restricted Stock Plan. Performance shares have been contingently granted to executive officers under the 2002 LTIP. A total of 1,566,875 shares have been authorized under all of the Company's share-based compensation plans, and 96,673 shares are available for future grants as of June 30, 2006. The 2002 LTIP is the only plan with shares available for future grants. To date, the Company has not granted stock appreciation rights as a form of compensation.

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Currently, the Company settles stock options, common shares and restricted stock from authorized but unissued common shares. Under the existing compensation plans, they may also be settled by the issuance of treasury shares or through open market purchases 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, performance shares have been settled in the form of shares of the Company's common stock.

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 six months ended June 30, 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     Expired Options outstanding and exercisable at June 30	652,321  (46,110) -  (39,204) (4,500) 562,507	$17.02  $14.64  -  $19.78  $16.23  $17.03	5.3 4.9	$221   $1,277

Cash received from exercise of stock options was about $0.7 million for the first half of 2006 and $0.3 million for the first half of 2005. The tax benefit realized for the tax deductions from option exercises was about $0.1 million for the first half of 2006 and 2005. Adoption of SFAS No. 123R for stock options did not impact the Company's 2006 consolidated results since all outstanding options were fully vested at December 31, 2005, and no stock options have been subsequently granted.

In the first half of 2005, the Company granted 73,071 stock options with a weighted-average grant-date fair value of $3.55. The aggregate intrinsic value of options exercised during the first half of 2005, amounted to $0.1 million. The fair value of stock options granted in 2005 was estimated as of the grant date using the Black-Scholes option pricing model, with the weighted-average assumptions shown in the table below.

Volatility
Risk-free rate of return
Dividend yield
Expected life (years) 25.82%
4.35%
5.11%
5.04

The volatility assumption was based on the historical volatility of the Company's common stock over a period equal to the option's expected term. The risk-free rate of return was based on the yield at the date of grant of a U.S. Treasury security with a maturity period approximating the option's expected term. The dividend yield assumption was based on historical dividend payouts. The expected term of options granted was based on historical experience.

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Common and Nonvested Shares Under the 2002 LTIP, common stock can be granted to executive officers, key employees and non-employee directors. The shares vest immediately or cliff vest over predefined service periods. 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 six months ended June 30, 2006, common and nonvested share activity was as follows:

	Shares	Weighted Average Grant-Date Fair Value
Nonvested at January 1     Granted     Vested     Deferred     Forfeited Nonvested at June 30	892  12,230  (6,057) (673)         -  6,392	$22.41  $20.68  $20.42  $20.42  -  $21.18

Compensation cost for the grant of common and nonvested shares is based on the market value of the Company's underlying common stock on the date of grant and recognized over the vest period. In the second quarter of 2006, the Company granted 6,730 shares of common stock to the Board of Directors as part of their annual retainer, which includes a combination of cash and shares of the Company's common stock. Common stock granted to the Board of Directors vests immediately, and individual directors can elect to defer receipt of their retainer under the terms of the Deferred Compensation Plan for Directors and Officers. In the first half of 2006, the Company also granted a total of 5,500 nonvested shares to certain executive officers, with vesting periods ranging from two to three years.

The Company recorded compensation expense of about $0.2 million in the second quarter and first half of 2006 and $0.1 million for the second quarter and first half of 2005 related to common and nonvested shares. Unearned compensation expense related to nonvested shares at June 30, 2006 was less than $20,000 to be recognized over a weighted average period of 1.6 years. The weighted-average grant-date fair value of common and nonvested shares granted in the first half of 2005 was $20.93 per share. The intrinsic value of shares vested during the first half of 2005 was zero since the shares were granted at the fair market value of the Company's common shares on the date of grant, and vested immediately.

Performance Shares The executive officer long-term incentive program is delivered in restricted stock in the form of contingent performance shares of common stock. Prior to January 1, 2006, the executive officer long-term incentive program 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 zero to 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-cycle due to retirement, death, disability or a change-in-control, that employee or their estate is entitled to receive a pro rata portion of shares.

During the six months ended June 30, 2006, performance share activity was as follows:

	Performance   Shares (1)	Weighted Average Grant-Date Fair Value
Outstanding at January 1 (unvested)     Granted     Dividend equivalents accrued     Vested     Forfeited Outstanding at June 30 (unvested)	37,300  33,800  3,933  -            -  75,033	$20.84 $17.50 $20.28 -           -  $19.30
(1) The number of common shares related to performance shares may range from zero to 150 percent of the number shown in the table above based on the achievement of operational and TSR measures relative to the three-year performance cycles.

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The Company recorded compensation expense of about $0.2 million in the second quarter and $0.3 million in the first half of 2006 related to performance shares. No performance share awards were made in the first quarter of 2006 since the Company did not meet the performance objectives for the performance cycle that ended December 31, 2005. Unrecognized compensation expense related to nonvested performance shares as of June 30, 2006 amounted to $0.7 million and is expected to be recognized over a weighted-average period of 1.5 years.

The weighted-average grant-date fair value of performance shares granted in the first half of 2005 was $20.62 per share. The Company recorded no compensation expense related to performance shares in the second quarter of 2005 and reversed previously recorded compensation expense of about $0.1 million in the first half of 2005 because targeted financial goals were not expected to be achieved.

The fair value of performance shares related to operational measures was estimated based on the expected outcome of each measure. Compensation cost is recognized in net income over the three-year vesting life, based on the shares that ultimately vest, and adjusted for the actual target percentage achieved. The fair value of performance shares related to TSR measures was estimated on the date of grant using a Monte Carlo simulation model. Compensation cost is recognized in net income on a straight-line basis over the three-year vesting life, based on the shares that ultimately vest, and is not adjusted for the actual target percentage achieved. The weighted-average assumptions used in the Monte Carlo valuation for TSR performance shares granted in 2006 are shown in the table below.

Volatility
Risk-free rate of return
Dividend yield
Term (years) 23.10%
4.29%
4.98%
3.0

The volatility assumption was based on the historical volatility of the Company's common stock over the three-year period ending on the grant date. The risk-free rate of return was based on the yield at the date of grant of a U.S. Treasury security with a maturity period of three years. The dividend yield assumption was based on historical dividend payouts. The expected term of performance shares is based on a three-year cycle. The weighted-average assumptions used in the Monte Carlo valuation for the TSR performance shares granted in 2004 and 2005 were the same as those used for stock options described above.

NOTE 8 - PENSION AND POSTRETIREMENT BENEFITS

At June 30, 2006, the fair value of Pension Plan trust assets was $76.0 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. The accrued pension benefit obligation recorded on the Condensed Consolidated Balance Sheets was $6.0 million at June 30, 2006 and $15.7 million at December 31, 2005.

At June 30, 2006, the fair value of Postretirement Plan trust assets was $10.5 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. The accrued postretirement benefit recorded on the Condensed Consolidated Balance Sheets was a liability of $0.1 million at June 30, 2006, and $3.5 million at December 31, 2005.

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

Pension Benefits	Three Months Ended June 30,    2006                2005		Six Months Ended June 30,    2006                2005
Net benefit costs include the following components Service cost Interest cost Expected return on plan assets Amortization of prior service cost Recognized net actuarial loss Net periodic benefit cost Less amounts capitalized Net benefit costs expensed	$922  1,493  (1,436) 100       196  1,275       202  $1,073	$807  1,464  (1,317) 100        49  1,103     176   $927	$1,844  2,986  (2,872) 200       392  2,550       406  $2,144	$1,614  2,928  (2,634) 200         98  2,206       343  $1,863

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Postretirement Benefits	Three Months Ended June 30,    2006                2005		Six Months Ended June 30,    2006                2005
Net benefit costs include the following components Service cost Interest cost Expected return on plan assets Recognized net actuarial loss Amortization of transition obligation Net periodic benefit cost Less amounts capitalized Net benefit costs expensed	$177  424  (179) 398       64  884     140   $744	$128  361  (119) 278       64  712     114   $598	$354  848  (358) 796        128  1,768        282  $1,486	$256  722  (238) 556        128  1,424        222  $1,202

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

NOTE 9 - 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 June 30, 2006, the Company had regulatory assets of about $4.2 million related to Maine Yankee, $9.1 million related to Connecticut Yankee and $4.3 million related to Yankee Atomic (including about $0.4 million for incremental decommissioning costs already paid by the Company that are now being recovered in retail rates pursuant to the 2005 Rate Order). These estimated costs are being collected from customers through existing retail rate tariffs. Pursuant to the 2005 Rate Order, beginning April 1, 2006, any differences between actual decommissioning cost payments and amounts included for recovery in retail rates are being deferred until the Company's next rate proceeding. See Note 3 - Retail Rates and Regulatory Accounting.

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 and included 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 any 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.

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Connecticut Yankee: The Company has a 2 percent ownership interest in Connecticut Yankee. Decommissioning of the nuclear plant is ongoing with transition to spent fuel storage operations only, expected in July 2007. 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 Connecticut Yankee'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 on 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 retail ratepayers.

On November 22, 2005, the Administrative Law Judge ("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 the 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 the 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 cannot be predicted at this time. See Note 12 - Subsequent Events for additional information related to Connecticut Yankee.

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 physical decommissioning and final regulatory approval by the NRC expected in May 2007, 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 the 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, the 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 with 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. On June 15, 2006, the settlement judge certified the settlement agreement to the FERC as uncontested. The proposed settlement agreement will become effective upon approval by the FERC, but the settlement should not materially affect the level of charges expected in 2006. See Note 12 - Subsequent Events for additional information related to the settlement agreement.

Millstone Unit #3 The Company has a 1.7303 percent joint ownership interest in Millstone Unit #3 and is responsible for its proportional 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. A schedule for further proceedings in the lawsuit has been set with a trial expected to be held in August 2008. Millstone Unit #3 spent fuel from the beginning of commercial operations in 1986 resides in the

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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 additional 20 years. This extends the licensed life from November 2025 to November 2045. In May 2006, DNC announced that it is studying an undetermined level of power uprate not to exceed 7 percent for Unit #3. If DNC decides to implement the uprate, a license amendment would be required to be submitted to the NRC. Certain plant hardware modifications and additional engineering studies would also be required. A 7 percent uprate would increase the Company's share of plant generation by about 1.4 MW, and the Company would be obligated to pay its ownership share of the related costs.

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.

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. The Company recorded these incremental replacement power costs in the fourth quarter of 2005. 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 included approval to apply the $1.1 million credit it received through VYNPC power bills in 2005 to reduce the deferral.

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. After the Company filed its May 15, 2006 rate increase request with the PSB, which included recovery of the replacement power costs, the Company and the PSB agreed to combine the review and final decision on the Accounting Order with the rate proceeding. Therefore, a final decision on the Accounting Order is expected in late January 2007. If the PSB approves the Company's request for an Accounting Order, the result would be a net deferral of $3.6 million for recovery from retail customers. To the extent the PSB denies or reduces recovery of the replacement power costs, the Company's rate request would be reduced accordingly. The Company cannot 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, representing a 20 percent increase in plant capacity. 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 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 remainder for costs incurred when the plant ran at a reduced ("derated") level due to the uprate project. Pursuant to the 2005 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's pending rate request includes amortization of this proposed regulatory liability. The Company cannot predict the timing or outcome of this matter at this time.

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On March 2, 2006, the NRC gave final approval to the uprate. Since that time Vermont Yankee plant output has increased to the expected uprate level of 120 percent. The Company has been purchasing a share of uprate power at market rates. On a pre-tax basis, these purchases amounted to about $3.9 million in the second quarter and $4.3 million in the first half of 2006, but there is no effect on net income since the Company is reselling the power to ISO-New England at the same market rates. The purchases are included in Purchased Power - affiliates and the related resale sales are included in Operating Revenues on the Condensed Consolidated Statement of Income.

On June 8, 2006, the plant received a new output rating of approximately 620 MW. Presuming the plant's rating remains at that level, the Company's share of the plant's output should be equivalent to the amount it received before the uprate process began. There is a risk that if the plant needs to reduce its rating (a "derate"), the Company's share of energy output would also be reduced proportionately under the terms of the PPA. The Company estimates that a derate could have a material adverse effect on its net power costs, if it results in a significant drop in VYNPC purchases at PPA rates.

The Company is currently a party to a PSB Docket, which was opened in June 2006 as a result of the DPS seeking additional ratepayer protections in the event there is a derate of plant output specifically as a result of issues relating to the steam dryer at the plant. This matter is expected to be resolved in September 2006. While the Company cannot predict the outcome of this matter at this time, it does not believe there could be an adverse outcome and certain outcomes could provide further protection.

The PPA between ENVY and VYNPC contains a formula for determining the entitlement to power following the uprate. VYNPC and ENVY are seeking to resolve certain differences in the interpretation of the formula. One issue is how much capacity VYNPC and ENVY may bid into the ISO-New England market following the uprate. Until the issues are resolved, ENVY and VYNPC have agreed that VYNPC will bid approximately 524 MW of capacity into the market, and ENVY will bid approximately 96 MW, with ENVY holding its proceeds in escrow until the issues are resolved. While the Company cannot predict the outcome of this issue, it does not expect that the outcome will have a material adverse effect on its financial position or results of operations.

In 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 ENVY 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. Prior to these actions, 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.

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 for approximately 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. 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.

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 year's 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 as measured at certain agreed upon metering stations on regulated and unregulated rivers in Quebec. This second option can be exercised five times through October 2015.

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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. Total purchases under the VJO Contract amounted to $15.6 million in the second quarter and $31.8 million in the first half of 2006, and $13.7 million in the second quarter and $28.9 million in the first half of 2005.

Performance Assurance At June 30, 2006, the Company had posted $11.7 million of collateral under performance assurance requirements for certain of its power contracts, as described 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+', its 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 June 30, 2006, the Company posted $2.0 million of collateral with ISO-New England, which is included in Restricted Cash on the Condensed Consolidated Balance Sheet. Previously ISO-New England collateral payments were maintained in a pooled fund and the Company's share of those payments was included in Special Deposits on the Condensed Consolidated Balance Sheet. A policy change made by ISO-New England in the second quarter of 2006 now requires the Company to deposit funds in a Restricted Cash account.

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 below investment grade, but only if requested to do so by the counterparties. As of June 30, 2006, the Company posted $9.7 million of collateral related to these two third-party contracts, which is included in Special Deposits on the Condensed Consolidated Balance Sheet. Collateral requirements for one of the contracts are reviewed on a weekly basis, and the other 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 those companies used coal to produce gas for retail sale. This practice ended more than 50 years ago. Gas manufacturers, their predecessors and the Company used waste disposal methods that were legal and acceptable then, but may not meet modern environmental standards and could represent a liability.

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

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

Brattleboro Manufactured Gas Facility In the 1940s, the Company owned and operated a manufactured gas facility in Brattleboro, Vermont. The Company ordered a site assessment in 1999 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. In the second quarter of 2006, the Company engaged a consultant to update the cost estimate related to this site reflecting increased redevelopment activity in adjacent sites. While redevelopment plans for the area have not been finalized, the recent acquisition of an adjacent site by the Town of

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Brattleboro and other recent activity have helped to better define the probable timing and nature of work that will be required for remediation of this site. Prior to this time there were several proposals for use of the site but none more likely than the other to occur. The updated cost estimate has not been finalized.

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.

The Company's reserve for environmental matters described above amounted to $5.4 million as of June 30, 2006 and $5.4 million as of December 31, 2005. The current and long-term portion of the reserve is recorded on the Condensed Consolidated Balance Sheets. The reserve represents management's best estimate of the cost to remedy issues at these sites based on available information as of the end of the reporting periods. At June 30, 2006, management believes its obligation related to these sites ranges from a high of $7.6 million to a low of $4.5 million. To the Company's knowledge, there is no pending or threatened litigation regarding other sites with the potential to cause material expense. No government agency has sought funds from 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 that is not subject to the deductible. The Company's estimated "maximum potential" amount of future payments related 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 10 - PENDING ACQUISITIONS

Rochester Electric On April 6, 2006, the Company entered into an agreement to purchase substantially all of the utility assets of Rochester Electric Light and Power at net book value. Rochester Electric Light and Power is a privately owned electric utility with its principal place of business in Rochester, Vermont, serving about 900 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 the third quarter of 2006. The purchase requires prior approval of the PSB.

See Note 12 - Subsequent Events for additional information regarding the Company's pending acquisitions.

NOTE 11 - 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 to customers in Vermont and New Hampshire through a subsidiary, SmartEnergy Water Heating Services, Inc., 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, 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.

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The accounting policies of operating segments are the same as those described in the summary of significant accounting policies. Inter-segment revenues are excluded from the table below since they amount to less than $10,000 in each of the periods presented. Financial information by segment follows (in thousands):

Three Months Ended June 30	CV VT	Eversant Corporation	Catamount Resources and Other	Discontinued Operations	Reclassification and Consolidating Entries	Consolidated
2006
Revenues from external customers (1) Equity in earnings from affiliates Income from continuing operations Total assets at June 30, 2006	$78,992  352  846  472,865	$469  -  97  1,967	-  -  $52  1,798	-  -  -  -	$(469) -  -  (4,511)	$78,992  352  995  472,119
2005
Revenues from external customers (1) Equity in earnings from affiliates Income from continuing operations Income from discontinued operations, net of tax Total assets at December 31, 2005	$75,116  478  2,540  -  496,483	$466  -  98  - 1,824	-  -  $(4)  -  58,780	-  -  -  $(544)  -	$(466) -  -  -  (5,654)	$75,116  478  2,634  (544)  551,433

Six Months Ended June 30	CV VT	Eversant Corporation	Catamount Resources and Other	Discontinued Operations	Reclassification and Consolidating Entries	Consolidated
2006
Revenues from external customers (1) Equity in earnings from affiliates Income from continuing operations Total assets at June 30, 2006	$161,247  869 4,498  472,865	$919  -  189  1,967	-  -  $405  1,798	-  -  -  -	$(919) -  -  (4,511)	$161,247  869 5,092  472,119
2005
Revenues from external customers (1) Equity in earnings from affiliates (Loss) income from continuing operations Income from discontinued operations, net of tax Total assets at December 31, 2005	$150,780  961  (2,498) -  496,483	$923  -  218  - 1,824	-  -  $(1)  -  58,780	-  -  -  $(256) -	$(923) - - -  (5,654)	$150,780  961  (2,281) (256) 551,433
(1) Eversant revenue is included in Other Income on the Condensed Consolidated Income Statements.

NOTE 12 - SUBSEQUENT EVENTS
Connecticut Yankee In July 2006, Connecticut Yankee determined that it could no longer conclude that it is probable it will recover about $10 million of decommissioning costs in its wholesale decommissioning charges. These costs relate to Connecticut Yankee's April 2000 rate case settlement, which specified that if Connecticut Yankee's costs for the physical decommissioning of the plant exceeded a specified level, then, subject to certain conditions, Connecticut Yankee would not bill its wholesale purchasers for 10 percent of the overage, up to a maximum of $10 million, even if the higher costs were prudently incurred. Connecticut Yankee recorded a $6 million after-tax reduction in its equity in the second quarter of 2006, since recovery of those costs is no longer probable. The Company recorded its share of the write-off, about $0.1 million after-tax, in the second quarter of 2006.

2005 Rate Order Appeal On July 18, 2006, the Court issued its decision rejecting the Company's appeal of certain portions of the 2005 Rate Order. The Court's decision has no effect on the Company's financial condition or results of operations for 2006 since the effect of the 2005 Rate Order was recorded in the first quarter of 2005. See Note 3 - Retail Rates and Regulatory Accounting for additional information.

Vermont Electric Cooperative On July 27, 2006, the Company entered into an agreement to purchase the assets and franchise territory of the Vermont Electric Cooperative ("VEC"), a Vermont corporation and electric cooperative, which serves approximately 37,000 customers, most of whom are located in central and northern Vermont. Under the agreement, which must be approved by the PSB, the Company will acquire the retail electric and distribution systems and facilities in several small towns in southern Vermont, and the franchise to serve 2,770 customers. The purchase price is expected to be about $4.0 million which represents 80 percent of the net book value of the assets being acquired. A petition for approval has

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been filed with the PSB and, if the transaction is approved, the Company expects a closing in December 2006.

Yankee Atomic On July 31, 2006, the FERC issued an Order approving the settlement agreement that had been filed on May 1, 2006. This allows a revised estimate of decommissioning costs through 2010 to be included in rates through 2014.

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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 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 earnings for the second quarter of 2006 were $1.0 million, or 8 cents per basic and diluted share of common stock, and $5.1 million, or 43 cents per basic and diluted share of common stock, for the first half of 2006. This compares to second quarter 2005 consolidated earnings of $2.1 million or 17 cents per basic and diluted share of common stock, and a consolidated loss of $2.5 million, or 22 cents per basic and diluted share of common stock, for the first half of 2005. Results for the second quarter of 2005 included a loss from discontinued operations of $0.5 million, or 4 cents per basic and diluted share of common stock, and $0.3 million, or 2 cents per basic and diluted share of common stock, for the first half of 2005. Results for the first half of 2005 also included a $21.8 million pre-tax charge to earnings, or 91 cents per diluted share of common stock, related to the 2005 Rate Order. The primary drivers of the year-over-year variances are described in detail in Results of Operations.

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The second quarter 2005 downgrade of our credit rating to below investment grade has had a significant effect on our liquidity. We are now required to post collateral under performance assurance requirements for certain of our power contracts. As of August 7, 2006 our total estimated collateral requirement was about $9.3 million. We have a $25.0 million unsecured credit facility available to support operating needs including the posting of collateral. At June 30, 2006 there were no borrowings or letters of credit outstanding under this facility. Although we have taken steps to help ensure adequate 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, or supplemental credit facilities.

Our top priorities are returning to an investment grade credit rating and improving communications with our Vermont regulators. Our ongoing liquidity and ability to make necessary investments in our electric system could be greatly reduced without the combination of a rate increase within the next 18 months and ongoing efforts to control rising costs. On May 15, 2006, we filed with the PSB a request for a 6.15 percent retail rate increase, to be effective February 1, 2007. A PSB decision on our 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 the fourth quarter of 2005, is also expected in January 2007.

On June 30, 2006, we invested $8.9 million in Vermont Transco LLC ("Transco"), a Vermont limited liability company formed by Vermont Electric Power Company, Inc. ("VELCO") and its owners, including us. In return we received a 20.1 percent equity ownership interest in Transco represented by Class A Units with an allowed rate of return of 11.5 percent. We plan to invest an additional $14.4 million in Transco in the third quarter of 2006.

BUSINESS RISKS
We regularly identify, monitor and assess our exposure to risk and seek to mitigate the risks inherent in our energy business. However, there are risks that are beyond our control or that cannot be limited cost-effectively or that may occur despite our risk mitigation strategies. The primary risk factors affecting our business include timely and adequate rate relief, our current credit rating, which is below investment grade, availability of power supply sources, volatility in wholesale power market prices and our ability to maintain liquidity to support ongoing operations. These risk factors could have a material effect on our financial position, results of operations or cash flows. These are discussed in more detail in Retail Rates, Liquidity and Capital Resources and Power Supply Matters below.

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 ("2005 Rate Order") that 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 2005 Rate Order resulted in a $21.8 million pre-tax charge to utility earnings in the first quarter of 2005.

On June 22, 2005, we filed an appeal of portions of the 2005 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 described 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 focused on whether the 2005 Rate Order set 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. On July 18, 2006, the Court issued its decision rejecting our appeal. The Court's decision has no effect on our financial condition or results of operations for 2006 since the effect of the 2005 Rate Order was recorded in the first quarter of 2005.

On May 15, 2006, we filed a request for a 6.15 percent rate increase to be effective February 1, 2007.  If approved, the rate increase will raise about $16.4 million from retail electric customers on an annual basis. Much of the increase is attributable to capital investments in distribution and transmission. The case is proceeding pursuant to an agreed-upon schedule, and a decision is expected in late January 2007.  We cannot predict the outcome of the rate proceeding at this time.

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LIQUIDITY AND CAPITAL RESOURCES
Liquidity

At June 30, 2006, we had cash and cash equivalents of $10.7 million included in total working capital of $26.6 million. During the first half of 2006, cash and cash equivalents increased by $4.1 million. The increase resulted from the following:

Operating Activities of Continuing Operations:  Operating activities provided $14.7 million. Net income, when adjusted for depreciation, amortization, deferred income tax and other items provided about $18.2 million. Additionally, collateral requirements under certain power contracts decreased by $9.4 million and changes in working capital and other items provided $4.7 million. This was partially offset by a $12.2 million pension trust fund contribution, $4.1 million in postretirement trust fund contributions, and $1.6 million in postretirement and other benefit-related payments, offset by $0.3 million of contributions received from plan participants.

Investing Activities of Continuing Operations:  Investing activities provided $45.9 million, including $66.3 million in proceeds from net sales and maturities of available-for-sale securities. We sold about $50 million of available-for-sale securities for the purchase of shares of our common stock through our tender offer that concluded in April 2006. We used about $9.5 million for construction expenditures, $8.9 million for our investment in Transco, and $2.0 million of restricted cash to meet ISO-New England collateral requirements.

Financing Activities of Continuing Operations: Financing activities used $56.5 million, including $51.2 million for the tender offer, $5.5 million for dividends paid on common and preferred stock and $0.5 million for capital lease payments. These items were partially offset by $0.7 million from stock issuance proceeds resulting from stock option exercises.

Available-for-sale Securities: Investments in available-for-sale securities at June 30, 2006 included $10.6 million with original maturities from 90 days to one year and $1.0 million with original maturities greater than one year.

VELCO and Transco:  In June 2006, VELCO's Board of Directors, the PSB and FERC approved a plan to transfer substantially all of VELCO's assets and business operations to Transco, a Vermont limited liability company formed by VELCO and its owners, including us. On June 30, 2006, we invested $8.9 million in Transco and on July 31, 2006 we invested $0.4 million. We expect to invest an additional $14 million in the third quarter of 2006. Our investments in Transco will earn an allowed return of 11.5 percent. Based on current projections, we expect to invest about $11 million to $13 million in 2007 and $2 million to $4 million in 2008 into Transco. In total, our investments in Transco from 2006 through 2008 could amount to between $35 million and $40 million. VELCO's investment projections for Transco are subject to change based on a number of factors, including revised construction project estimates and timing of regulatory project approvals. Our investment plans in Transco are also subject to change due to circumstances including those involving our liquidity.

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

Retail Rates:  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) continues to negatively impact our cash flow from operations. On May 15, 2006, we filed a request for a 6.15 percent increase in retail electric rates to be effective February 1, 2007.

Rochester Electric: On April 6, 2006 we 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 customers. The purchase price is about $250,000, and the transaction is expected to be completed in the third quarter of 2006. The purchase requires prior approval of the PSB.

Vermont Electric Cooperative: On July 27, 2006, we entered into an agreement to purchase the southern Vermont franchise territory and related assets of Vermont Electric Cooperative ("VEC"), a Vermont corporation and electric cooperative, which serves approximately 37,000 customers primarily in central and northern Vermont. Under the agreement, we will acquire the retail electric and distribution systems and facilities in several small towns in southern Vermont, and the franchise to serve 2,770 customers. The purchase will provide new revenue and a wider base to allocate our fixed costs. The purchase price is expected to be about $4 million, which represents 80 percent of the net book value of the assets being acquired. A petition for approval has been filed with the PSB and, if the transaction is approved, we expect a closing in December 2006.

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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 August 2006, the Senate passed, without modification, the Pension Protection Act of 2006, which was passed in July 2006 by the House of Representatives.  The Act can now be sent to the President for his signature and passed into law.  Passage of the Act provides clarity for plan sponsors concerning the funding of defined benefit pension plans. The Act also includes significant provisions on defined contribution plans, hybrid plans, nonqualified deferred compensation and health care benefits.  We have not evaluated the impact on our cash flows, results of operations or financial position.

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 until the end of 2007. However, an extended Vermont Yankee plant outage or similar event could significantly impact our liquidity due to the potentially high cost of replacement power and performance assurance requirements arising from purchases through ISO-New England or third parties. In the event of an extended Vermont Yankee plant outage, we 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 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 June 30, 2006 there were no borrowings or letters of credit outstanding under this facility.

Covenants:  At June 30, 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.

Credit Ratings

On August 1, 2006, Standard and Poor's Ratings Services ("S&P") reaffirmed our BB+ corporate credit rating and our BBB senior secured bond rating. Our preferred stock rating was lowered to B+ from BB-. In their press release, S&P explained that "The lowering of the preferred stock rating reflects Standard and Poor's notching criteria for preferred stock of speculative-grade companies. The criteria requires preferred stock to be rated three notches below the corporate credit rating." In addition, S&P revised our business risk profile score to reflect a less risky rating of "5" from our previous score of "6". (S&P ranks utilities on a scale of "1" or "excellent" to "10" or "vulnerable".) This was in response to our sale of Catamount, the major portion of our unregulated businesses.

At our own initiation, we are no longer rated by Fitch Ratings.

Performance Assurance
As of June 30, 2006, we had posted $11.7 million of collateral under performance assurance requirements for certain of our power contracts, primarily as a result of having our credit rating reduced 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 June 30, 2006, we had posted $2.0 million of collateral with ISO-New England.

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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 below investment grade, but only if requested to do so by the counterparties. As of June 30, 2006, we posted $9.7 million of collateral related to these third-party contracts. Collateral requirements for one of the contracts are reviewed on a weekly basis, and the other can be reviewed on a daily basis by either party. As of August 7, 2006, our total collateral requirement under these contracts is estimated to be about $9.3 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 increase 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.

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 $27.4 million on a pre-tax basis as of June 30, 2006. We would also be required to determine any impairment to the carrying costs of deregulated plant.

Environmental Liabilities Our regulated electric business is engaged in various operations and activities that subject it to inspection and supervision by both federal and state regulatory authorities including the United States Environmental Protection Agency. Our policy is to accrue a liability for those sites where costs for remediation, monitoring and other future activities are probable and can be reasonably estimated. At June 30, 2006, we had a reserve of $5.4 million for three environmental sites that are in various stages of remediation.

In the second quarter of 2006, the Company engaged a consultant to update the cost estimate related to one site located in Brattleboro, Vermont due to increased redevelopment activity in adjacent sites. While redevelopment plans for the area have not been finalized, the recent acquisition of an adjacent site by the Town of Brattleboro and other recent activity have helped to better define the probable timing and nature of work that will be required for remediation of this site. Prior to this time, there were several proposals for use of the site but none more likely than the other to occur. The updated cost estimate has not been finalized. We have also engaged the consultant to update the cost estimate for another site located in Rutland, Vermont. These cost estimates are in various stages of completion. At this time, we cannot predict how or if the revised estimates will impact our financial condition or results of operations.

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Share-Based Compensation We adopted SFAS No. 123R, Share-Based Payment, ("SFAS No. 123R") on January 1, 2006 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 instruments issued. Prior to adoption of SFAS No. 123R, we accounted for our share-based compensation plans under APB No. 25, Accounting for Stock Issued to Employees, and related guidance. Although adoption of SFAS No. 123R did not have a material effect on our financial position or results of operations, we are now required to estimate the grant-date fair value of the Total Shareholder Return ("TSR") measures contained in our performance share plans using an appropriate fair-value model that meets the requirements of SFAS No. 123R and related guidance. We are using the Monte Carlo valuation model to value TSR performance shares. The model is complex and the assumptions used in the calculations require considerable judgment. Compensation cost is recognized in net income on a straight-line basis over the three-year vesting life, and is not adjusted for the actual target percentage achieved. See Note 7 - Share-Based Compensation Plans for additional information.

We recorded pre-tax compensation expense of $0.4 million for all share-based compensation in the second quarter and $0.5 million in the first half of 2006. We recorded pre-tax compensation expense of $0.1 million for all share-based compensation for the second quarter and a nominal amount for the first half of 2005. There are no amounts capitalized for share-based compensation, and the compensation expense is primarily included in the same income statement line item as cash compensation to the same employees. See discussion of Results of Operations below.

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 sheet 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 $4.1 million at June 30, 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 contract for the sale of about 15 MW per hour, beginning November 17, 2004 through December 31, 2008. 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 $7.9 million at June 30, 2006 and $12.9 million at December 31, 2005.

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 three and six months ended June 30, 2006 compared to the same periods in 2005. This should be read in conjunction with the condensed consolidated financial statements and accompanying notes included in this report.

Consolidated Summary
Consolidated earnings for the three months ended June 30, 2006 were $1.0 million, or 8 cents per basic and diluted share of common stock. This compares to consolidated earnings of $2.1 million or 17 cents per basic and diluted share of common stock for the same period in 2005. Second quarter 2005 results included a loss from discontinued operations of $0.5 million, or 4 cents per basic and diluted share of common stock.

Consolidated earnings for the six months ended June 30, 2006 were $5.1 million, or 43 cents per basic and diluted share of common stock. This compares to a consolidated loss of $2.5 million, or 22 cents per basic and diluted share of common

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stock for the same period in 2005. Results for the first half of 2005 included a $21.8 million pre-tax charge to earnings, or 91 cents per diluted share of common stock, related to the 2005 Rate Order, and a loss from discontinued operations of $0.3 million, or 2 cents per basic and diluted share of common stock. The table below provides a reconciliation of diluted earnings per share.

	2006 versus 2005
	Three Months Ended		Six Months Ended
2005 earnings (loss) per diluted share		$.17		$(.22)
Year-over-Year Effects on Earnings:
Higher resale revenue	.28		.39
CRC higher earnings in 2006	.01		.04
Lower other operating revenue	(.03)		(.04)
Lower retail revenue (a)	(.04)		(.13)
Higher purchased power costs (a)	(.25)		(.39)
Other variances, net (a)	(.10)		(.15)
Subtotal		(.13)		(.28)
Net impact of one-time 2005 Rate Order charge		-		.91
Discontinued operations - 2005 losses		.04		.02
2006 Earnings per diluted share		$.08		$.43
(a) - Excludes 2005 Rate Order charges for six months ended June 30, 2005.

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. Retail sales revenue can be affected by weather and economic conditions since these factors impact customer use. Resale sales are related to the sale of excess power from our owned and purchased power supply portfolio. Resale sales revenue can be affected by the availability of power for resale and the market or contract price for those sales. Operating revenues and related mWh sales are summarized below:

	Three months ended June 30,				Six months ended June 30,
	mWh Sales		Revenues (in thousands)		mWh Sales		Revenues (in thousands)
	2006	2005	2006	2005	2006	2005	2006	2005
Retail sales:  Residential  Commercial  Industrial  Other retail   Total retail sales Resale sales Retail customer refund Other revenues   Total	214,537 208,896 101,632     1,541 526,606 312,804 -             -  839,410	217,311 210,835 96,548     1,344 526,038 185,751 -            -  711,789	$28,227  24,580  8,181         446  61,434  15,757  -      1,801  $78,992	$28,697  25,187  7,867         392  62,143  10,689  -       2,284   $75,116	481,482 425,555 216,452       3,051 1,126,540 527,619 -               -  1,654,159	490,989 427,898 205,706        2,675 1,127,268 338,283 -               -  1,465,551	$61,901  49,583  17,882         882    130,248    27,295              -      3,704  $161,247	$63,984  50,895  17,214         785    132,878      19,660     (6,197)      4,439  $150,780

Operating revenues for the second quarter and first half of 2006 include resale revenue associated with the sale of additional power that we are purchasing under the long-term contract with Vermont Yankee Nuclear Power Corporation ("VYNPC"). In mid-March 2006, the Vermont Yankee plant completed an uprate that increased its hourly output by about 20 percent. Under the terms of the long-term contract ("PPA"), we are required to purchase a share of this uprate energy at market rates, referred to as Vermont Yankee uprate energy. We resell the energy to ISO-New England at the same market price, since it is not needed to serve our customers. Therefore, the additional sales and purchases have no effect on net income.

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Operating revenues increased $3.9 million, or 5.2 percent, in the second quarter of 2006 compared to the same period in 2005, including $3.9 million for the resale of Vermont Yankee uprate energy. Year-over-year variances within the primary components of operating revenues are as follows:

• Retail sales decreased $0.7 million primarily due to lower residential and commercial customer use, partly offset by higher industrial customer use. The mWh volume of retail sales remained about the same for the comparative periods, but the change in use between customer classes resulted in lower revenue because the unit price for residential and commercial customers is slightly higher than for industrial customers. Lower residential and commercial use reflects milder weather and a shift of one large commercial customer to industrial.
• Resale sales increased $5.1 million because more mWh were available for resale, including $3.9 million for the resale of Vermont Yankee uprate energy. The remaining $1.2 million increase was due to increased deliveries under the long-term contract with Hydro-Quebec, and higher output from our owned and jointly owned generating units and from Independent Power Producers ("IPP"). Since retail sales were about the same in both periods, the additional power from these sources was available for sale through forward sale contracts and the wholesale markets in ISO-New England. The resale revenue associated with these sales was partially offset by the cost to purchase the power as described in Purchased Power below.
• Other revenues decreased about $0.5 million due to lower transmission revenue and increased reserves related to a proposed pole attachment tariff settlement, partly offset by revenue from a vehicle auction in the second quarter of 2006.

Operating revenues increased $10.5 million, or 6.9 percent, in the first half of 2006 compared to the same period in 2005. 2006 included $4.3 million for the resale of Vermont Yankee uprate energy. 2005 included a first-quarter $6.2 million 2005 Rate Order-required customer refund. Year-over-year variances within the primary components of operating revenues are as follows:

• Retail sales decreased $2.6 million, including $1.9 million related to the 2.75 percent rate reduction that began in April 2005, and $0.7 million related to lower residential and commercial customer use, partly offset by higher industrial customer use. The reasons are the same as those described above.
• Resale sales increased $7.6 million because more mWh were available for resale, including $4.3 million for the resale of Vermont Yankee uprate energy. The remaining $3.3 million increase resulted from the same factors as described above.
• The PSB-required retail customer refund reduced revenue by $6.2 million in 2005, resulting in a favorable variance when comparing 2006 to 2005. The 2005 Rate Order required the refund for amounts determined by the PSB to be 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 $0.7 million primarily due to the same factors as described above.

Purchased Power Our purchases of power constituted about 55 percent of total operating expenses for the second quarter and first half 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 June 30,				Six Months Ended June 30,
	mWh Purchases		Purchases (in thousands)		mWh Purchases		Purchases (in thousands)
	2006	2005	2006	2005	2006	2005	2006	2005
VYNPC (a) Hydro-Quebec Independent Power Producers   subtotal long-term contracts Short-term and misc. purchases SFAS No. 5 loss amortizations Maine Yankee, Connecticut    Yankee and Yankee Atomic (a) March 29, 2005 Rate Order Other Total purchased power	454,767 233,171   55,718 743,656 3,266 -  -  -              -746,922	383,027 182,521    47,354 612,902 22,419 -  -  -                -     635,321	$19,495  15,566      6,269  41,330  179  (299) 1,542  -         231  $42,983	$15,341  13,726       5,457  34,524  2,741  (299) 1,405  -           94  $38,465	847,252 488,686    106,412 1,442,350 28,641 -  -  -                -     1,470,991	763,001 411,437    80,312 1,254,750 60,293 -  -  -                -   1,315,043	$35,403  31,798    12,952  80,153  2,652  (598) 2,907  -         357  $85,471	$30,557  28,897     10,026  69,480  6,672  (598) 2,195  2,441         122  $80,312
(a) Purchased power transactions with affiliates. Amounts shown in the table above are shown net of regulatory amortizations and deferrals including our share of VYNPC nuclear insurance settlements that we deferred per a PSB Order, and deferral of Yankee Atomic incremental dismantling costs prior to April 1, 2005, when they were eliminated in accordance with the 2005 Rate Order.

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Purchased power expense for the second quarter and first half of 2006 includes additional purchases of Vermont Yankee uprate energy. As described in Operating Revenues above, these purchases are offset by resale sales, therefore there is no income statement impact related to these purchases.

Purchased power expense increased $4.5 million, or 11.7 percent, in the second quarter of 2006 compared to the same period in 2005, including $3.9 million for the purchase of Vermont Yankee uprate energy. Year-over-year variances within the primary components of purchased power expense are described below.

• Long-term purchases increased $6.8 million primarily related to 1) additional purchases of Vermont Yankee uprate energy (93,248 mWh), and to a lesser extent increased capacity offset by slightly lower output, absent the uprate energy; 2) more deliveries from Hydro-Quebec due to a change in the capacity factor from 65 percent to 80 percent for the annual contract year beginning November 1, 2005; and 3) higher output from IPPs due to more rainfall in 2006 versus 2005.
• Short-term purchases decreased $2.5 million because more power was available from long-term contracts and wholly and jointly owned generating units, and certain ISO-New England charges that are included in the average market price declined from last year.
• Other power costs increased about $0.2 million, primarily related to regulatory amortizations associated with Millstone Unit #3's scheduled refueling outages. Based on approved regulatory accounting treatment, we defer the cost of incremental replacement energy and maintenance costs of scheduled refueling outages, and amortize those costs through the next scheduled refueling outage, which typically spans over an 18-month period. Millstone Unit #3's last scheduled refueling outage occurred in October 2005.

Purchased power expense increased $5.1 million, or 6.4 percent, in the first six months of 2006 compared to the same period in 2005. This year included $4.3 million for the purchase of Vermont Yankee uprate energy. Last year included first quarter 2005 Rate Order-required charges of $2.5 million. Year-over-year variances within the primary components of purchased power expense are described below.

• Long-term purchases increased $10.7 million primarily due to the same factors described above, including: 1) additional purchases of Vermont Yankee uprate energy (99,228 mWh); 2) more deliveries from Hydro-Quebec; and 3) higher output from Independent Power Producers.
• Short-term purchases decreased $4.0 million for the same reasons described above.
• 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 $0.7 million due to higher FERC-approved rates and the elimination of accounting deferrals in 2005 per the 2005 Rate Order. Our obligations related to these plants are described in Nuclear Generating Units below.
• Accounting entries related to the 2005 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 resulting from a 2004 unscheduled outage. The 2005 Rate Order charge results in a favorable variance when comparing 2006 versus 2005.
• Other power costs increased about $0.2 million for the same reasons described in the second quarter variance above.

Operating Expenses Operating expenses represent costs incurred to support our core business. Operating expenses increased $5.3 million in the second quarter of 2006 and $6.3 million in the first half of 2006 versus comparable periods in 2005. Excluding purchased power expense described above, this amounts to a $0.8 million increase in the second quarter and a $1.1 million increase in the first half of 2006. These increases are primarily related to the income statement line items discussed below.

Transmission - affiliates and other: These expenses are associated with transmission of electricity. The increases of $0.9 million for the second quarter of 2006 and $1.2 million for the first half of 2006 are primarily related to higher VELCO demand-based charges mostly due to higher levels of VELCO depreciation in 2006. Other factors were higher load dispatch and market facilitation charges, offset by lower open access transmission charges resulting from our share of Highgate savings credits that began in the second quarter of 2005.

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 $8.7 million decrease in 2006 reflects the impact of first-quarter 2005 Rate Order charges of $10.7 million. The remaining $2.0 million increase was due to higher external audit fees and higher employee-related costs including medical, pension, long-term disability, workers' compensation and share-based compensation, partly offset by the favorable

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effect of regulatory amortizations beginning in April 2005. Also, in 2005 we incurred bondholder consent fees of about $0.2 million with no comparable item in 2006. The $10.7 million 2005 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 $2.5 million increase in the first half of 2006 is related to higher storm restoration costs in the first quarter of 2006 and higher contractor costs for tree trimming. Pursuant to the 2005 Rate Order, beginning April 1, 2005, any differences between actual tree trimming costs and amounts included for recovery in retail rates are being deferred until our next rate proceeding. Therefore, the higher tree trimming costs are offset by the favorable impact of regulatory amortizations described above.

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. Taxes on income for the second quarter and first half of 2006 include the effect of a lower expected effective tax rate due to permanent differences and tax credits that reduced the effective tax rate. Taxes on the operating loss for the first half of 2005 included the effect of a higher expected effective tax rate due to permanent timing differences and tax credits that increased the effective tax rate.

Other Income and Deductions These items are related to the non-operating activities of our utility business and the operating and non-operating activities of our non-regulated businesses. The $2.0 million increase for the first half of 2006 is primarily related to the income statement line items discussed below.

Other income: These items include non-operating rental income mostly from rental water heaters, interest and dividend income; interest on temporary investments and miscellaneous other income items. The $1.7 million increase in the first half of 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 2005 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 $0.8 million decrease in the first half of 2006 includes $0.4 million related to a first-quarter 2005 Rate Order charge due to the disallowance of a portion of Vermont Yankee fuel rod costs. The remaining $0.4 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.

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 on the credit facility. The $1.3 million decrease for the first half of 2006 is primarily 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).

	Three Months Ended June 30, 2006                  2005		Six Months Ended June 30, 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 (deductions) Total interest expense Net loss from discontinued operations	$-    -    -  -  -  -    -    -  -    -  $-	$-  (93) 93  427  431  (1,438)     73     (507) (414)    130  $(544)	$-    -    -  -  -  -    -    -  -    -  $-	$-  (192) 192  1,359  1,614  (3,252)     35     (244) (52)    204  $(256)

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 in 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.

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 as measured at certain agreed upon metering stations on regulated and unregulated rivers in Quebec. This second option can be exercised five times through October 2015.

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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. The Company recorded these incremental replacement power costs in the fourth quarter of 2005. 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. We also requested approval to apply the $1.1 million credit we received through VYNPC power bills in 2005 to reduce the deferral.

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. After we filed our May 15, 2006 rate increase request with the PSB, which included recovery of the replacement power costs, we and the PSB agreed to combine the review and final decision on the Accounting Order with the rate proceeding. Therefore, a final decision on the Accounting Order is expected in late January 2007. If the PSB approves our request for an Accounting Order the result would be a net deferral of $3.6 million for recovery from retail customers. To the extent the PSB denies or reduces recovery of the replacement power costs, our rate request would be reduced accordingly. We cannot 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, representing a 20 percent increase in plant capacity. 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).

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 remainder for costs incurred when the plant ran at a reduced ("derated") level due to the uprate project. Pursuant to the 2005 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. Our pending rate order request includes amortization of this proposed regulatory liability. We cannot predict the timing or outcome of this matter at this time.

On March 2, 2006, the NRC gave final approval to the uprate. Since that time Vermont Yankee plant output has increased to the expected uprate level of 120 percent. We have been purchasing a share of uprate power at market rates. As described in Results of Operations above, these purchases have no effect on net income since the power is being resold in ISO-New England at market rates.

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On June 8, 2006, the plant received a new output rating of approximately 620 MW. Presuming the plant's rating remains at that level, our share of the plant's output should be equivalent to the amount we received before the uprate process began. There is a risk that if the plant needs to reduce its rating ("derate") our share of energy output would also be reduced proportionately under the terms of the PPA. We estimate that a derate could have a material adverse effect on our net power costs, if it results in a significant drop in VYNPC purchases at PPA rates.

We are currently a party to a PSB Docket, which was opened in June 2006 as a result of the DPS seeking additional ratepayer protections in the event there is a derate of plant output specifically as a result of issues relating to the steam dryer at the plant. This matter is expected to be resolved in September 2006. While we cannot predict the outcome of this matter at this time, we do not believe there could be an adverse outcome and certain outcomes could provide us with further protection.

The PPA between ENVY and VYNPC contains a formula for determining the entitlement to power following the uprate. VYNPC and ENVY are seeking to resolve certain differences in the interpretation of the formula. One issue is how much capacity VYNPC and ENVY may bid into the ISO-New England market following the uprate. Until the issues are resolved, ENVY and VYNPC have agreed that VYNPC will bid approximately 524 MW of capacity into the market, and ENVY will bid approximately 96 MW, with ENVY holding its proceeds in escrow until the issues are resolved. While we cannot predict the outcome of this issue, we do not expect it to have a material adverse effect on our financial position or results of operations.

In 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 ENVY 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. Prior to these actions, 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.

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 for approximately 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. 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.

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.

Wholly Owned Generating Units We own and operate 20 hydroelectric generating units, two oil-fired gas turbines and one diesel peaking unit with a combined nameplate capability of about 74.2 MW.

In January 2003, we, the Vermont Agency of Natural Resources ("VANR"), Vermont Natural Resources Council and other parties reached an agreement to allow us to relicense the four dams we own and operate on the Lamoille River. According to the agreement, we were to receive a water quality certificate from the State, which is needed for FERC to relicense the facilities for 30 years. The agreement also stipulates that subject to various conditions, we must begin decommissioning the Peterson Dam in about 20 years. The agreement requires PSB approval of full rate recovery related to decommissioning the Peterson Dam, including recovery of replacement power costs when the dam is out of service. In July 2003, the VANR published its draft water quality certificate. In October 2003, pursuant to the schedule set forth in the agreement, we filed a petition with the PSB for approval of the rate recovery mechanisms, and the case has continued to progress through the regulatory process.

In June 2005, FERC issued a 30-year license for the four dams including Peterson Dam. While FERC determined that the VANR waived its rights to issue a water quality certificate, the license includes conditions, previously agreed upon by us, the DPS, VANR and other parties, relating to project operations, fish and wildlife, recreation, land use, and historic properties.

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The license does not include conditions relating to decommissioning of the Peterson Dam in 20 years, or cost recovery. In July 2006, a Hearing Officer issued a Proposal for Decision recommending that the PSB deny the requested orders to decommission the Peterson Dam. Resolution of this matter requires approval by the PSB.

We and the VANR asked for rehearing of the June 2005 FERC order, and in November 2005, FERC issued a decision upholding its order and denying rehearing requests. The decision also clarified certain terms of the license. In January 2006, we and the VANR filed timely appeals in federal court. In response to a motion by VANR, which was unopposed by the FERC Staff and us, the federal court has stayed all action on the appeals until completion of the proceedings before the PSB and further filings by the parties to determine the future proceedings in the appeals. The 30-year license remains in effect during such appeals. We cannot predict the outcome of these matters at this time.

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. These plants are described in more detail below.

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 the 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 June 30, 2006, we had regulatory assets of about $4.2 million related to Maine Yankee, $9.1 million related to Connecticut Yankee and $4.3 million related to Yankee Atomic (including about $0.4 million for incremental decommissioning costs already paid by us that are now being recovered in retail rates pursuant to the 2005 Rate Order). These estimated costs are being collected from customers through existing retail rate tariffs. Pursuant to the 2005 Rate Order, beginning April 1, 2006, any differences between actual decommissioning cost payments and amounts included for recovery in retail rates are being deferred 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 any 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.

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Connecticut Yankee: We have a 2 percent ownership interest in Connecticut Yankee. Decommissioning of the nuclear plant is ongoing with transition to spent fuel storage operations only, expected in July 2007. 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 on 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.

On November 22, 2005, the Administrative Law Judge ("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.

We continue to believe that the 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 the FERC disallows cost recovery in wholesale 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.

In July 2006, Connecticut Yankee determined that it could no longer conclude that it is probable it will recover about $10 million of decommissioning costs in its wholesale decommissioning charges. These costs relate to Connecticut Yankee's April 2000 rate case settlement, which specified that if Connecticut Yankee's costs for the physical decommissioning of the plant exceeded a specified level then, subject to certain conditions, Connecticut Yankee would not bill its wholesale purchasers for 10 percent of the overage, up to a maximum of $10 million, even if the higher costs were prudently incurred. Connecticut Yankee recorded a $6 million after-tax reduction in its equity in the second quarter of 2006, since recovery of those costs is no longer probable. We recorded our share of the write off, about $0.1 million after-tax, in the second quarter of 2006.

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 physical decommissioning and final regulatory approval by the NRC expected in May 2007, 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 the 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, the 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. On June 15, 2006, the settlement judge certified the settlement agreement to the FERC as

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uncontested. On July 31, 2006, the FERC issued an Order approving the settlement agreement. This allows a revised estimate of decommissioning costs through 2010 to be included in rates through 2014. The settlement should not materially affect the level of charges expected in 2006.

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. A schedule for further proceedings in the lawsuit has been set with a trial expected to be held in August 2008. 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. This extends the licensed life from November 2025 to November 2045. In May 2006, DNC announced that it is studying an undetermined level of power uprate not to exceed 7 percent for Unit #3. If DNC decides to implement the uprate, a license amendment would be required to be submitted to the NRC. Certain plant hardware modifications and additional engineering studies would also be required. A 7 percent uprate would increase our share of plant generation by about 1.4 MW, and we would be obligated to pay our ownership share of the related costs.

DIVERSIFICATION
CRC's earnings were about $0.1 million in the second quarter of 2006 and $0.6 million in the first half of 2006. This compares to earnings of about $0.1 million in the second quarter of 2005 and $0.2 million in the first half of 2005. The $0.4 million increase in the first half of 2006 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. In its 2005 session, the Vermont Legislature passed Act 61, "Renewable Energy, Efficiency, Transmission, and Vermont's Energy Future" ("Act 61"), a law that includes two major provisions of interest to us:

1. Power Supply Requirements - The 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 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.

In the first quarter of 2006, we agreed in principle to purchase all of the output (about 47.5 MW of power) from a proposed wind project on Glebe Mountain in Londonderry, Vermont.  During the second quarter of 2006, wind project developer Glebe Mountain Wind Energy LLC announced that it was not going forward with the project.  Accordingly, we no longer anticipate that this project will be a renewable energy resource for us.

2. 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.

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In 2006, the Vermont Legislature passed Act 208, "Vermont Energy Security and Reliability Act" ("Act 208"), a law that includes three provisions that may impact the Company:

1. Net Metering - 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. The new law amends the current statute to: allow any renewable energy source to be utilized for net metering; allow all projects a rolling 12-month credit and any credits not used in that time to revert to the utility and count towards SPEED-required total; and enables a utility to charge fees and book and defer costs for all systems greater than 15 kilowatt capacity. Act 208 also directs the PSB to expand the scope of net metering in Vermont. Although exactly how net metering is to be expanded is left to the PSB's discretion, the PSB must consider increasing the existing 150 kilowatt cap on individual net metering projects, increasing the overall net metering cap that stands at 1 percent of a utility's load, and allowing a utility's customers to join together to collectively net meter.

2. Rate Design - The new law directs the PSB to approve rate designs to encourage the efficient use of natural gas and electricity, including consideration of the creation of an inclining block rate structure for residential rate customers with an initial block of low-cost power available to all residences.

3. Affordability Program - The new law requires the PSB to design a proposed electricity affordability program in the form of draft legislation developed with the aid of an electricity affordability program collaborative for consideration by the Vermont Legislature in January 2007. We are currently participating in this effort.

At this time, we are not able to predict how, or if, changes resulting from Act 61 or Act 208 will affect our financial condition or results of operations.

RECENT ACCOUNTING PRONOUNCEMENTS
In March 2006, FASB issued an exposure draft that would 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.

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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 as of June 30, 2006 follows (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 June 30, 2006 - unrealized loss	$(12,935)       5,077  $(7,858)	$(4,977)       847  $(4,130)
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	$(10,728) $(5,437)	$(7,354) $(1,851)

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.

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 June 30, 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 material change in our internal control over financial reporting that occurred during the first six months 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.

1. Formalize the process for identifying and documenting the accounting, reporting and tax implications for new, non-routine and non-recurring transactions.
2. 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.
3. 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.

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Our remediation plan has not been fully implemented as of June 30, 2006. Therefore, 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 in the second quarter of 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
April 1 - April 30			2,249,975	$22.50	2,249,975
May 1 - May 31			-	-	-
June 1 - June 30			-	-	-
Second quarter 2006			2,249,975	$22.50	2,249,975

There were no other shares repurchased other than through the Tender Offer described in Footnote 2, below. On February 7, 2006, Central Vermont announced a Tender Offer to repurchase up to 2,250,000 shares of our Common Stock using approximately $50,000,000, at a target price rate from $20.50 to $22.50, to expire on March 15, 2006. Central Vermont repurchased the shares on April 19, 2006. See also: Form 8-K dated February 6, 2006 and filed on February 7, 2006. On March 14, 2006 the Tender Offer was extended until April 5, 2006. See also: Form 8-K dated March 9, 2006 and filed on March 14, 2006.
Item 6.	Exhibits.
	(a)	List of Exhibits
		31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
		31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
		32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
		32.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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SIGNATURE

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

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

Dated  August 8, 2006

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

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