CENTRAL VERMONT PUBLIC SERVICE CORPORATION

10-Q 1 fnl10q.htm FORM 10-Q PERIOD ENDED SEPTEMBER 30, 2006 CENTRAL VERMONT PUBLIC SERVICE CORPORATION UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q

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

For the quarterly period ended September 30, 2006

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

For the transition period from _______ to _______

Commission file number 1-8222

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

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

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

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

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

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

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

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

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. As of October 31, 2006 there were outstanding 10,127,250 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 nine months ended September 30, 2006 and 2005	3
	Condensed Consolidated Statements of Comprehensive Income (unaudited) for the three and nine months ended September 30, 2006 and 2005	4
	Condensed Consolidated Statements of Cash Flows (unaudited) for the nine months ended September 30, 2006 and 2005	5
	Condensed Consolidated Balance Sheets as of September 30, 2006 (unaudited) and December 31, 2005	6
	Condensed Consolidated Statement of Changes in Common Stock Equity for the nine months ended September 30, 2006 and 2005 (unaudited)	8
	Notes to Condensed Consolidated Financial Statements	9
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	34
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	55
Item 4.	Controls and Procedures	55
PART II	OTHER INFORMATION	57
SIGNATURES		58
EXHIBIT INDEX		59

Page 2 of 59


CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS) (in thousands, except share data) (unaudited)
	Three Months Ended		Nine Months Ended
	September 30		September 30
	2006	2005	2006	2005
Operating Revenues	$79,912	$75,035	$241,159	$225,815

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	21,076 20,102 2,403 (2,038) 4,130 9,291 5,172 4,155 3,623 4,210 72,124	15,720 23,919 2,879 292 3,544 9,941 4,823 4,099 3,497 2,389 71,103	58,936 67,713 7,595 806 11,082 34,949 16,018 12,375 10,867 6,172 226,513	47,380 72,571 7,893 2,286 10,120 44,286 13,142 12,254 10,432 (1,150) 219,214
Operating Income	7,788	3,932	14,646	6,601
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	825 31 1,111 (451) (249) 1,267	485 19 1,224 (653) (94) 981	1,694 94 4,559 (1,915) (846) 3,586	1,446 51 2,940 (2,903) (162) 1,372
Total Operating and Other Income	9,055	4,913	18,232	7,973
Interest Expense Interest on long-term debt Other interest Allowance for borrowed funds during construction Total Interest Expense	1,799 262 (10) 2,051	1,800 230 (6) 2,024	5,397 770 (31) 6,136	5,398 1,983 (16) 7,365
Income from continuing operations Loss from discontinued operations, net of income tax Net Income Dividends declared on preferred stock Earnings (loss) available for common stock	7,004 - 7,004 92 $6,912	2,889 (168) 2,721 92 $2,629	12,096 - 12,096 276 $11,820	608 (424) 184 276 $ (92)
Per Common Share Data: Basic: Earnings from continuing operations Loss from discontinued operations Earnings (loss) per share Diluted: Earnings from continuing operations Loss from discontinued operations Earnings (loss) per share	$.67 - $.67 $.66 - $.66	$.22 (.01) $.21 $.22 (.01) $.21	$1.08 - $1.08 $1.07 - $1.07	$.02 (.03) $(.01) $.02 (.03) $(.01)
Average shares of common stock outstanding - basic Average shares of common stock outstanding - diluted Dividends declared per share of common stock	10,328,099 10,403,040 $.23	12,276,642 12,365,263 $.23	10,966,169 11,026,662 $.69	12,251,944 12,251,944 $.92

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

Page 3 of 59

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (in thousands) (unaudited)
	Three Months Ended September 30		Nine Months Ended September 30
	2006	2005	2006	2005
Net Income	$7,004	$2,721	$12,096	$184
Other comprehensive income, net of tax: Investments: Unrealized holding gain net of taxes of $28, $49, $54 and $55 Realized loss (gain) net of taxes of $14, $(11), $(10), $103 Foreign currency Other comprehensive income from discontinued operations, net of taxes of $0, $(132), $0 and $(93)	41 21 -	71 (16) (197)	79 (16) -	81 150 (139)
Comprehensive Income	$7,066	$2,579	$12,159	$276

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

Page 4 of 59

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)

Nine Months Ended September 30,

    2006

    2005

Cash flows provided (used) by:
OPERATING ACTIVITIES
Net income
Deduct: Loss from discontinued operations, net of income taxes
    Income 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 (net of $6.5 million customer refund)
     Non-cash employee benefit plan costs
     Environmental reserve adjustment
     Share-based compensation
     Net gains and amortization of premiums on available-for-sale securities
     Non-utility depreciation and other
     Gain on sales of property
     Changes in assets and liabilities:
           Decrease in accounts receivable and unbilled revenues
           Decrease in accounts payable
           Increase (decrease) in accrued income taxes
           Decrease in other current assets
           Decrease (increase) in special deposits
           Increase 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

$12,096
         -
12,096

(1,694)
1,311
12,375
(1,791)
510
-
7,472
(1,609)
629

(24)
81
(290)

3,194
(3,684)
1,439
1,444
19,066
2,105
(27,677)
        94
25,047

$184
  424
608

(1,446)
1,471
12,254
302
(5,067)
15,312
5,943
-
8
873
113
-

4,704
(4,897)
(3,642)
641
(21,532)
2,495
(6,273)
   62
  1,929

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
     Catamount sale costs (previously accrued)
     Acquisition of utility property - Rochester
     Premiums paid for Rabbi trust life insurance policies
     Increase in restricted cash
     Proceeds from sales of property
     Return of capital from investments in affiliates
     Other
Net cash provided by investing activities of continuing operations

(15,123)
(256,417)
325,450
(23,291)
-
-
(309)
(209)
(385)
(99)
334
263
   (98)
30,116

(11,324)
(205,076)
217,316
-
(5,900)
11,000
-
-
(179)
(507)
408

245
         7
  5,990

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
     Savings from share-based excess tax benefits and other
Net cash used for financing activities of continuing operations

1,182
(7,992)
(51,186)
1,300
(1,050)
(765)
         86
(58,425)

1,163
(9,099)
-
-
-
(758)
        (5)
  (8,699)

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

-
-
         -
         -

4,265
(11,921)
   8,250
    594

Net decrease in cash and cash equivalents
Cash and cash equivalents at beginning of the period
Cash and cash equivalents at end of the period

(3,262)
6,576
$3,314

(186)
   11,722*
$11,536*

*Assets of discontinued operations included cash of $3.1 million at September 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 59

CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)

(unaudited)
September 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

$522,257
  232,137
290,120
11,243
         988
  302,351

$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
      ($3,726 in 2006 and $4,063 in 2005)
  Millstone decommissioning trust fund
  Available-for-sale securities
  Other
Total investments and other assets

39,204

1,626
5,110
-
     6,901
   52,841

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
      ($3,001 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
  Assets held for sale
  Other current assets
Total current assets

3,314
8,926
983
28

23,141

76
13,249
5,300
7,402
3,513
388
        750
   67,070

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

22,427
12,573
     6,906
   41,906

$464,168

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 59

CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)

(unaudited)
September 30,          December 31,
        2006                           2005

CAPITALIZATION AND LIABILITIES
Capitalization
  Common stock, $6 par value, 19,000,000 shares authorized, 12,371,215      shares issued and 10,121,240 shares outstanding at September 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

$74,189
53,978
(351)
-
(51,186)
   96,400
173,030
8,054
3,000
115,950
     5,631
305,665

$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
3,306
10,659
11,050
2,161
2,113
2,326
2,978
1,614
  20,088
  57,295

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

29,762
3,815
12,851
2,907
6,882
7,003
14,006
  23,982
101,208

$464,168

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 59

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN COMMON STOCK EQUITY (unaudited)
	Shares		(in thousands)
	Common	Treasury	Common Stock	Other Paid-in Capital	Accum OCI	Deferred Comp.	Treasury Stock	Retained Earnings	Total
Nine months ended September 30, 2005
Balance, December 31, 2004 Net income 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, September 30, 2005	12,193,093 17,400 41,822 4,770 19,920 12,277,005	- -	$73,153 104 251 29 120 $73,657	$51,964 198 660 (50) (430) 20 $52,362	$(130) 92 $(38)	$(36) 29 $(7)	$- $ -	$99,702 184 (11,273) (276) $88,337	$224,653 184 92 302 911 8 (310) (11,273) (276) 20 $214,311
Nine months ended September 30, 2006
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 Loss on reacquisition of capital stock Balance, September 30, 2006	12,283,405 74,685 13,125 12,371,215	- 2,249,975 2,249,975	$73,695 448 46 $74,189	$52,513 867 578 13 7 $53,978	$(414) 63 $(351)	$(5) 5 $-	$- (51,186) $(51,186)	$91,581 12,096 (6,967) (276) (34) $96,400	$217,370 12,096 63 (51,186) 1,315 629 (6,967) (276) 13 (27) $173,030

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

Page 8 of 59

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 nine months ended September 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 accompanying notes 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 Vermont Department of Public Service ("DPS") is the public advocate for utility customers. 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 $21.0 million on a pre-tax basis as of September 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.

Page 9 of 59

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

	September 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	$2,415 4,023 4,310 1,984 2,327 1,196 898 698 2,237 $20,088	$2,569 3,253 3,016 3,021 1,257 1,196 1,167 941 3,828 $20,248

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

	September 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	$960 8,155 4,955 9,866 46 $23,982	$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 September 30, 2006 2005		Nine Months Ended September 30, 2006 2005
Interest on temporary investments Non-utility revenue and non-operating rental income Amortization of contributions in aid of construction - tax adder Other interest and dividends Regulatory asset carrying costs* Gain of sale of non-utility property Miscellaneous other income Total	$245 483 223 150 - - 10 $1,111	$300 488 210 192 - - 34 $1,224	$ 1,509 1,423 661 479 - 317 170 $4,559	$1,006 1,454 628 451 (653) 12 42 $2,940
*For nine months ended September 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 September 30, 2006 2005		Nine Months Ended September 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	$88 320 43 - - $451	$150 297 - - 206 $653	$565 943 - - 407 $1,915	$575 874 573 403 478 $2,903

Page 10 of 59

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	September 30, 2006
Net unrealized (loss) gain on investments Non-qualified benefit obligations Accumulated other comprehensive income (loss)	$(20) (394) $(414)	$63 - $63	$43 (394) $(351)

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. 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. For awards granted after adoption of SFAS No. 123R, compensation costs are 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.

Prior to adoption of SFAS No. 123R, the Company accounted for its share-based compensation plans under APB No. 25 and related guidance, and 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. Compensation costs for all share-based compensation were recognized over the nominal (stated) vesting period.

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 expense for all share-based compensation in 2006 of $0.1 million in the third quarter and $0.6 million in the first nine months, and tax benefits of less than $0.1 million and $0.2 million for the respective periods. 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 nine months of 2006, excess tax benefits of $0.1 million are included in Financing Activities on the Condensed Consolidated Statement of Cash Flows. The Company recorded compensation expense and related tax benefits of a nominal amount in the third quarter and first nine months of 2005.

Page 11 of 59

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

	September 30, 2005
	Three Months Ended	Nine Months Ended
Earnings (loss) available for common stock, as reported Add: Share-based compensation expense included in reported net income, net of tax Deduct: Share-based compensation expense under fair value method, net of tax Pro forma net income Earnings per share: Basic - as reported Basic - pro forma Diluted - as reported Diluted - pro forma	$2,629 6 6 $2,629 $.21 $.21 $.21 $.21	$(92) 5 135 $(222) $(.01) $(.02) $(.01) $(.02)

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 September 30, 2006 2005		Nine Months Ended September 30, 2006 2005
Numerator for basic and diluted EPS: Income from continuing operations Dividends declared on preferred stock Net income 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	$7,004 (92) $6,912 10,328,099 67,731 7,210 10,403,040	$2,889 (92) $2,797 12,276,642 83,729 4,892 12,365,263	$12,096 (276) $11,820 10,966,169 55,523 4,970 11,026,662	$608 (276) $332 12,251,944 - - 12,251,944

Outstanding stock options totaling 17,500 in the third quarter of 2006 and 77,577 in the first nine months 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 third quarter of 2005, 298,651 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, prior to the fourth-quarter 2005 reclassification for discontinued operations.

Assets Held for Sale In the third quarter of 2006, the Company determined that one of its properties located in Middlebury, Vermont meets the criteria for classification as held for sale. The Company is actively pursuing potential buyers of the property, which previously housed one of its service centers. This asset is classified as held for sale on the Condensed Consolidated Balance Sheet in accordance with SFAS No. 144. Regulatory accounting treatment for the sale of utility-owned property requires that sale costs and any related loss or gain be offset against accumulated depreciation. The net book value of the property was $0.4 million at September 30, 2006.

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.

Page 12 of 59

Restricted Cash The Company held restricted cash of $1.0 million at September 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 September 30, 2006 also included collateral payments of $0.1 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 less than $0.1 million at September 30, 2006 and $21.1 million at December 31, 2005. The balance at December 31, 2005 included $19.1 million of collateral payments related to performance assurance requirements for certain of the Company's power contracts described in Note 9 - Commitments and Contingencies. All collateral payments had been returned to the Company during the first nine months of 2006, and partly replaced by a $4.5 million letter of credit issued during the third quarter of 2006. 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):

	Nine Months Ended September 30, 2006 2005
Cash paid during the year for: Interest (net of amounts capitalized) Income taxes (net of refunds)	$3,945 $3,957	$3,769 $6,427

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.

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 September 30, 2006, $0.2 million of construction and plant-related accruals were included in Accounts Payable, and less than $0.1 million was included in Other Current Liabilities. At December 31, 2005, $1.0 million of construction and plant-related accruals were included in Accounts Payable and $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 Employee benefit plan funding and related payments of $6.3 million and Non-cash employee benefit plan costs of $5.9 million from Other non-current assets and liabilities and other in Operating Activities on the 2005 Condensed Consolidated Statement of Cash Flows to separately report and conform to the 2006 presentation.

Eversant's results of operations, which were recorded on a net basis on the 2005 Statement of Income, have been reclassified, and its revenues and expenses are now reported on a gross basis. As a result, the Company reclassified $0.3 million in the third quarter and $0.8 million in the first nine months of 2005 from Other Income to Other Deductions. There was no impact on reported net income.

Interest expense related to two industrial redevelopment bonds, which was recorded as long-term on the 2005 Statement of Income, has been reclassified to short-term interest expense. As a result, the Company reclassified $0.1 million in the third quarter and $0.2 million in the first nine months of 2005 from Interest on Long-Term Debt to Other Interest. There was no impact on reported net income.

Page 13 of 59

The Company has reclassified $0.7 million from Transmission - other in the second quarter of 2006 to Transmission - affiliates in order to conform to year-to-date presentation on the Consolidated Statement of Income.

Recent Accounting Pronouncements

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

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.

SAB 108: In September 2006, the SEC issued Staff Accounting Bulletin No. 108 ("SAB 108"), Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, to eliminate the diversity in practice surrounding how public companies quantify financial statement misstatements. There have been two common methods for quantifying the effects of financial statement misstatements. One, referred to as the roll-over method, focuses primarily on the impact of a misstatement on the income statement, including the reversing effect of prior-year misstatements, but it can lead to the accumulation of misstatements on the balance sheet. The other, referred to as the iron-curtain method, focuses primarily on the effect of correcting the period-end balance sheet with less emphasis on the reversing effects of prior-year errors on the income statement. SAB 108 establishes an approach that requires quantification of errors under both methods, referred to as the dual approach. The provisions of SAB 108 are effective for annual financial statements covering the first fiscal year ending after November 15, 2006. The initial application of SAB 108 is not expected to impact the Company's financial position, results of operations or cash flows.

SFAS No. 157: On September 15, 2006, the FASB issued FASB Statement No. 157, Fair Value Measurements ("SFAS No. 157"), which addresses how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. As a result of SFAS No. 157, there is now a common definition of fair value to be used throughout GAAP. Companies must adopt SFAS No. 157 for financial statements issued for fiscal years beginning after November 15, 2007. The Company has not yet evaluated the impact that SFAS No. 157 will have on its financial position, results of operations and cash flows.

SFAS No. 158: On September 29, 2006, the FASB issued FASB Statement No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R) ("SFAS No. 158"). SFAS No. 158 requires, among other things, that a company (1) recognize a net liability or asset to report the funded status of their defined benefit pension and other postretirement plans on its balance sheet and (2) measure benefit plan assets and benefit obligations as of the company's fiscal year-end balance sheet date. The Company will adopt SFAS No. 158 as of December 31, 2006, as required. The Company is currently evaluating the impact that SFAS No. 158 will have on its financial position, results of operations and cash flows. Based on the annual measurement date of September 30, 2006, the Company has estimated that adoption of SFAS No. 158 could increase total pension and postretirement liabilities by approximately $30.0 million. The Company is evaluating whether it will seek regulatory accounting treatment for the potential balance sheet impacts of SFAS No. 158.

Page 14 of 59

NOTE 2 - INVESTMENTS IN AFFILIATES

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

Ownership

September 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%

30.28%

2.00%
2.00%
3.50%

$2,831

11,294
       220
11,514

23,640

859
326
         34
    1,219

$39,204

$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. The Company's ownership interest has increased from 20.1 percent in the second       quarter of 2006, as described in more detail below.

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2006	2005	2006	2005
Operating revenues Operating income (loss) Net income Company's equity in net income	$56,096 $865 $208 $122	$41,198 $543 $169 $100	$156,456 $2,634 $549 $323	$125,227 $(804) $511 $301

The Company received $0.1 million of cash dividends from VYNPC in the third quarter of 2006 and 2005, and $0.3 million in the first nine months of 2006 and 2005. VYNPC's revenues shown in the table above include sales to the Company of $19.6 million for the third quarter and $54.8 million for the first nine months of 2006, and $14.7 million for the third quarter and $43.8 million for the first nine months of 2005. These amounts, offset by deferral of nuclear insurance refunds and sale of a small percentage of the Company's 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 $5.8 million at September 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 now manage the operations of Transco under a Management Agreement between VELCO and Transco. Transco operates under an Operating Agreement among VELCO, Transco, the Company, Green Mountain Power and most of the other Vermont electric utilities. Transco also operates under the Amended and Restated Three Party Agreements, assigned to Transco from

Page 15 of 59

VELCO, among the Company, Green Mountain Power, VELCO and Transco. As of September 30, 2006, VELCO has a 31.2 percent interest in Transco, which results in a 14.68 percent indirect interest for the Company.

The Company has invested a total of $23.3 million in Transco in 2006, including $8.9 on June 30, $0.4 million on July 31 and $14.0 million on September 29. Total third quarter investments increased the Company's interest in Transco from 20.1 percent to 30.28 percent. The Company's ownership interest in Transco is represented by Class A Units that have an allowed rate of return of 11.5 percent. As of September 30, 2006, the Company's total direct and indirect interest in Transco is 44.96 percent. In addition to the Company's investments in Transco, and VELCO's initial transferred investment of $24.0 million, most of VELCO's other owners have also invested in Transco.

In the third quarter of 2006, the Company reassessed its ownership interests in Transco under the provisions of FIN 46R, Consolidation of Variable Interest Entities, and continues to conclude that Transco is not a variable interest entity. In the second quarter of 2006, the Company reassessed its ownership interest in VELCO and assessed its ownership interest in Transco and concluded that they were not variable interest entities.

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2006	2005	2006	2005
Operating revenues Operating income Net income Company's equity in net income	$7,745 $2,735 $1,348 $682	$7,248 $2,088 $739 $363	$25,201 $7,314 $2,850 $1,425	$22,754 $6,228 $2,212 $1,075

	September 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	$26,267 237,752 264,019 87,664 98,941 $ 77,414 $35,154	$26,044 161,504 187,548 93,397 69,745 $24,406 $11,462

VELCO's 2006 revenues in the table above include billings to the Company that amounted to a $2.0 million credit in the third quarter of 2006 and a $1.1 million charge in the first nine months of 2006. The third-quarter 2006 credit is related to the Company's share of NEPOOL Open Access Transmission Tariff reimbursements made to Transco for construction of transmission projects in Vermont. VELCO's 2005 revenues included billings to the Company of $0.3 million in the third quarter of 2005 and $2.3 million in the first nine months of 2005. These amounts are reflected in Transmission - affiliates on the Company's Condensed Consolidated Statements of Income. Accounts payable to VELCO amounted to $4.4 million at September 30, 2006 and $5.9 million December 31, 2005.

The Company received $0.3 million of cash distributions from VELCO in the third quarter of 2006, and $0.4 million for the same period in 2005. The Company received $1.0 million of cash distributions from VELCO in the first nine months of 2006 and $1.2 million for the same period in 2005, including $0.1 million for return of capital from VELCO's Class C preferred stock in both periods.

Page 16 of 59

The Company did not receive any cash dividends from Transco in the third quarter of 2006. Transco's summarized financial information, included in VELCO's consolidated financial information above, follows (in thousands):

	Inception June 30, 2006 to September 30, 2006
Operating revenues Operating income (loss) Net income Company's equity in net income	$7,849 $3,494 $2,060 $349

	September 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	$13,721 233,261 246,982 74,774 95,280 $76,928 $23,640	$ - - - - - $ - $ -

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 third quarter and $4.4 million for the first nine months of 2006, and $1.4 million for the third quarter and $4.0 million for the first nine months 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'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. The issues that were raised on appeal primarily focused on whether the 2005 Rate Order set rates retroactively without statutory authorization. On July 18, 2006, the Court issued its decision rejecting the Company's appeal. The Court's decision had no effect on the Company's financial condition or results of operations for 2006.

Page 17 of 59

On May 15, 2006, the Company filed a request for a 6.15 percent rate increase (additional revenue of $16.4 million on an annual basis), to be effective February 1, 2007. On September 11, 2006, the Company and the DPS reached a settlement in the case, agreeing to a 3.73 percent increase (additional revenue of $9.9 million on an annual basis) effective January 1, 2007. The agreement reduces the Company's proposed allowed rate of return on common equity from 12 percent to 10.75 percent. The settlement agreement has been filed with the PSB, which must review and approve the settlement before it can become effective. Also see Note 9 - Commitments and Contingencies related to the Company's request for an Accounting Order to defer incremental replacement power costs for a Vermont Yankee scheduled refueling outage in the fourth quarter of 2005.

A hearing on the settlement was held on October 31. The PSB has indicated it expects to issue a decision on the rate case settlement agreement on or before December 15, 2006.

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)
	September 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	$16,087 615 3,774 992 462 410 87 22,427	$20,995 1,538 3,810 2,481 1,154 384 82 30,444
Other deferred charges - regulatory Vermont Yankee sale costs (tax) Unrealized loss on power contract derivatives Nuclear decommissioning costs above amounts in retail rates Utility acquisitions costs Tree trimming and pole treating Subtotal Other deferred charges - regulatory	3,130 8,617 486 87 253 12,573	3,130 17,912 - - 3 21,045
Page 18 of 59
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 Environmental remediation (a) Other Subtotal Other deferred credits - regulatory	5,764 1,108 2,722 1,088 891 1,648 785 14,006	8,646 2,770 1,337 1,088 481 - 1,102 15,424
Net regulatory assets, deferred charges and deferred credits	$20,994	$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. (a) In the third quarter of 2006, the Company reduced its reserves for estimated environmental remediation costs based on revised cost estimates. The deferred credit represents the portion of the reserve reduction attributable to ratepayers. See Note 9 - Commitments and Contingencies for additional information.

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. See Note 9 - Commitments and Contingencies for indemnifications related to the sale. 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
September 30,
2006                  2005

Nine Months Ended
September 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 interest expense

Net loss from discontinued operations

$-
  -
  -

-
-
-
  -
  -

  -

$-

$-
  (83)
   83

27
1,218
(1,863)
    634
      16

    267

$(168)

$-
  -
  -

-
-
-
  -
  -

  -

$-

$-
  (275)
   275

1,386
2,832
(5,115)
    669
   (228)

   471

$(424)

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.

Page 19 of 59

The Company recorded $0.1 million of realized gains on available-for-sale securities in the first nine months of 2006, and none in the third quarter. The Company also recorded a nominal amount of impairments in both periods in 2006 based on securities expected to be redeemed prior to maturity. The Company recorded $0.2 million of realized losses on available-for-sale securities in the first nine months of 2005, and a nominal amount in the third quarter. The Company also recorded impairments of $0.3 million in the first nine months of 2005, and none in the third quarter.

The unrealized losses on available-for-sale securities shown below 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):

	September 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	$7,373 1,480 - 8,853 - 8,853 - - - $8,853	$60 20 - 80 - 80 - - - $80	$(7) - - (7) - (7) - - - $(7)	$7,426 1,500 - 8,926 - 8,926 - - - $8,926	$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 September 30, 2006 follows (in thousands):

Fair value of debt securities at contractual maturity dates

Debt Securities

Less than 1 year
$5,985

1 to 5 years
$2,941

5 to 10 years
-

After 10 years
-

Total
$8,926

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 September 30, 2006 (in thousands):

	Debt Securities
	Fair Value	Unrealized Losses
Less than 12 months (1 security) 12 months or more (1 security) Total	$999 1,492 $2,491	$(1) (6) $(7)

Page 20 of 59

Millstone Decommissioning Trust Fund The Company has decommissioning trust fund investments related to its joint-ownership interest in Millstone Unit #3. Changes in the fair value of these securities are recorded as Other deferred credits - regulatory on the Condensed Consolidated Balance Sheet. The fair value of these investments is summarized below (in thousands):

	September 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	$2,460 1,326 30 $3,816	$1,302 14 - $1,316	$(7) (15) - $(22)	$3,755 1,325 30 $5,110	$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 September 30, 2006 follows (in thousands):

	Fair value of debt securities at contractual maturity dates
Debt Securities	Less than 1 year $34	1 to 5 years $312	5 to 10 years $269	After 10 years $710	Total $1,325

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 September 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

$11
125
$136

$-
(7)
$(7)

$339
338
$677

$(3)
  (12)
$(15)

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). There are no restrictions on restricted stock once the shares vest, therefore they are referred to as nonvested shares under SFAS No. 123R.

Page 21 of 59

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 102,605 shares are available for future grants as of September 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.

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 nine months ended September 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 September 30	652,321 (74,685) - (46,704) (4,500) 526,432	$17.02 $15.82 - $20.00 $16.23 $16.94	5.3 4.8	$324 $1,791

Cash received from exercise of stock options was $1.2 million for the first nine months of 2006 and $0.3 million for the same period in 2005. The tax benefit realized for the tax deductions from option exercises was $0.1 million for the first nine months 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 nine months 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 nine months 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.

Page 22 of 59

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 nine months ended September 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 September 30	892 13,798 (7,625) (673) - 6,392	$22.41 $20.77 $20.63 $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 third quarter of 2006, the Company granted a total of 1,568 shares of common stock to the directors that resigned on May 2, 2006 as part of the Company's Board Restructuring Agreement Resolution. 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 nine months 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 for common and nonvested shares of less than $0.1 million in the third quarters of 2006 and 2005, and $0.3 million and $0.1 million in the first nine months of 2006 and 2005, respectively. Unearned compensation expense related to nonvested shares at September 30, 2006 was of a nominal amount. The weighted-average grant-date fair value of common and nonvested shares granted in the first nine months of 2005 was $20.93 per share. The intrinsic value of shares vested during the first nine months 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. 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.

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During the nine months ended September 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 September 30 (unvested)	37,300 33,800 9,699 - - 80,799	$20.84 $17.50 $19.19 - - $19.24
(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.

The Company recorded compensation expense of $0.1 million in the third quarter and $0.4 million in the first nine months of 2006 related to performance shares. No 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 September 30, 2006 amounted to $0.6 million and is expected to be recognized over a weighted-average period of 1.25 years.

The weighted-average grant-date fair value of performance shares granted in the first nine months of 2005 was $20.62 per share. The Company recorded no compensation expense related to performance shares in the third quarter of 2005 and reversed previously recorded compensation expense of $0.1 million in the first nine months 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 September 30, 2006, the fair value of Pension Plan trust assets was $86.1 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 and in September 2006, the Company contributed $8.6 million. The accrued pension benefit obligation recorded on the Condensed Consolidated Balance Sheets was an asset of $1.3 million at September 30, 2006 and liability $15.7 million at December 31, 2005.

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At September 30, 2006, the fair value of Postretirement Plan trust assets was $11.5 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 and in September 2006, the Company contributed $0.9 million. The accrued postretirement benefit obligation recorded on the Condensed Consolidated Balance Sheets was an asset of $0.4 million at September 30, 2006, and a liability $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 September 30, 2006 2005		Nine Months Ended September 30, 2006 2005
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 1,275 267 $1,008	$807 1,464 (1,317) 100 49 1,103 171 $932	$2,766 4,479 (4,308) 300 588 3,825 673 $3,152	$2,421 4,392 (3,951) 300 147 3,309 514 $2,795

Postretirement Benefits	Three Months Ended September 30, 2006 2005		Nine Months Ended September 30, 2006 2005
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 64 884 185 $699	$128 361 (119) 278 64 712 110 $602	$531 1,272 (537) 1,194 192 2,652 466 $2,186	$384 1,083 (357) 834 192 2,136 332 $1,804

The Medicare Part D subsidy included in Postretirement net periodic benefit cost was $0.2 million for the first nine months of 2006 and 2005 and is expected to be $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.

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 September 30, 2006, the Company had regulatory assets of $3.7 million related to Maine Yankee, $8.8 million related to Connecticut Yankee and $3.6 million related to Yankee Atomic (including $0.3 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.

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Department of Energy ("DOE") Litigation Maine Yankee, Connecticut Yankee and Yankee Atomic have been seeking recovery of fuel storage-related costs stemming from the default of the DOE under the 1983 fuel disposal contracts that were mandated by the United States Congress under the Nuclear Waste Policy Act of 1982. Under the Act, the 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.

On February 28, 2006, all three companies asked the Court to allow amended damage claim filings. 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. In the spring of 2006, the trial judge issued a ruling allowing Maine Yankee to seek recovery of damages through December 31, 2002, and Connecticut Yankee and Yankee Atomic to seek recovery of damages through December 31, 2001.

On September 30, 2006, United States Court of Federal Claims Senior Judge Merow issued a favorable ruling for Maine Yankee, Connecticut Yankee and Yankee Atomic in the DOE litigation. Maine Yankee was awarded $75.8 million in damages through 2002, Connecticut Yankee was awarded $34.1 million through 2001 and Yankee Atomic was awarded $32.9 million through 2001. The three companies had claimed actual damages through the same periods in the amount of $78.1 million for Maine Yankee, $37.7 million for Connecticut Yankee and $60.8 million for Yankee Atomic. Most of the reduction in the claimed losses related to disallowed wet pool operating expenses, which the Court felt the companies would have incurred notwithstanding the DOE breach.

Due to the complexity of the issues and the possibility of appeals, the three companies cannot predict the amount of damages that will actually 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 NRC amended its operating license for operation of the Independent Spent Fuel Storage Installation.

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

On March 7, 2006, Connecticut Yankee and Bechtel Power Corporation ("Bechtel") settled their disputes concerning Connecticut Yankee's July 2003 termination of Bechtel's decommissioning contract. 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.

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 required by the Initial Decision related to the escalation rate used to translate the original estimate into spending projections and decommissioning charges.

In July 2006, Connecticut Yankee determined that it could no longer conclude that it is probable it will recover $10 million of decommissioning costs in its wholesale decommissioning charges. Therefore, Connecticut Yankee recorded a $6.0 million after-tax reduction in its equity in the second quarter of 2006. The Company recorded its share of the write-off, $0.1 million after-tax, in the second quarter of 2006.

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On August 15, 2006, a proposed settlement of Connecticut Yankee's FERC Rate Case was filed with the FERC. Among the notable provisions of the settlement are the following: 1) the decommissioning collections schedule will be reduced to reflect the lower escalation factor starting January 1, 2007; 2) any claims of imprudence made in the docket against Connecticut Yankee in its decommissioning effort are resolved with no finding of imprudence; 3) the decommissioning collections schedule will credit ratepayers with the $15.0 million settlement payment from Bechtel to Connecticut Yankee in 2007, 2008 and 2009; 4) the decommissioning collections schedule will be reduced by $10 million as part of a budget incentive plan wherein timely license termination performance by Connecticut Yankee will offset some of the reduction; 5) the decommissioning collections schedule will be extended from 2010 to December 2015; 6) the decommissioning collections schedule will be subject to an investment earnings tracking mechanism for performance greater than or less than certain targets; and 7) Connecticut Yankee will resume reasonable payment of dividends to its stockholders subject to certain incentive target balances. This settlement, if approved by the FERC, will, among other things, result in lower decommissioning expenses for the Company over the near-term.

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 this settlement is 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 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 were to disallow cost recovery in wholesale rates, it is anticipated that the PSB would disallow these costs for recovery in retail rates as well. The FERC ruling on the filed settlement is expected by the end of 2006.

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 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. On January 31, 2006, the FERC issued an Order accepting the rate increase, effective February 1, 2006, subject to refund by Yankee Atomic after hearings and settlement judge proceedings.

On May 1, 2006, Yankee Atomic filed with the FERC a settlement agreement among all of the parties. On July 31, 2006, the FERC issued an Order approving the settlement agreement that reduces Yankee Atomic's November 2005 decommissioning cost estimate by $32.0 million and increases the number of years for revenue collection from 2010 to 2014 in order to provide near-term rate relief. Under the approved settlement agreement, Yankee Atomic agreed to reduce its revenue requirements by $79.0 million for the period 2006-2010 and to increase its revenue requirements by $47.0 million for the period 2011-2014. The revision includes adjustments for contingencies, projected escalation and certain decontamination and dismantling expenses. The approved settlement also provides for reconciling and adjusting future charges based on actual decontamination and dismantling expenses and the decommissioning trust fund's actual investment earnings. The Company believes that its share of the increase in decommissioning costs will ultimately be recovered from customers.

Millstone Unit #3 The Company has a 1.7303 percent joint ownership interest in Millstone Unit #3 and is responsible for its share of nuclear decommissioning costs. In January 2004, 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 trial is expected to be held in August 2008. 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 an additional 20 years, extending the license 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. A 7 percent uprate would increase the Company's share of plant generation by 1.4 MW, and the Company would be obligated to pay its ownership share of the related costs.

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Vermont Yankee As of September 15, 2006, the Company has a 29 percent entitlement in Vermont Yankee plant output sold by ENVY to VYNPC. Its entitlement was reduced from 35 percent due to the plant power output uprate described below, but the Company is still purchasing about 180 MW of plant output. These purchases are made through the PPA with VYNPC. One remaining secondary purchaser continues to receive a small percentage (less than .2 percent) of its entitlement. 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.

Prior to the change in the Company's entitlement percentage, the Company purchased a share of uprate power at market rates from mid-March through mid-September based on the terms of the PPA. On a pre-tax basis, these purchases amounted to $4.1 million in the third quarter and $8.4 million in the first nine months of 2006. The Company sold the power in the wholesale energy markets 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.

The following provides a more detailed discussion of items of interest related to the Company's power purchases from VYNPC.

October 2005 Refueling Outage: 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. The price for replacement power was significantly higher than what was being recovered in retail rates. The Company recorded net incremental replacement power costs of $5.4 million in the fourth quarter of 2005. On December 23, 2005, the Company filed a request for an Accounting Order from the PSB to defer $3.6 million for recovery in its next rate proceeding. The request included $4.7 million for net incremental replacement power costs above those already embedded in retail rates, and application of the $1.1 million credit the Company received through a VYNPC power bill 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 expected from 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. The PSB's review and final decision on the Accounting Order request was subsequently combined with the Company's May 15, 2006 rate increase request.

On September 11, 2006, the Company reached a settlement agreement with the DPS on its rate increase request. The agreement does not resolve the Accounting Order request, but it does include application of the $1.1 million received through a VYNPC power bill in 2005. The Company and the DPS have since filed amended testimony with the PSB on the Accounting Order request, which is now in the amount of $4.7 million. If the PSB approves all or a portion of the request, the amount would be deferred for recovery from retail customers, resulting in a favorable impact on net income, since the costs were previously expensed. If the PSB denies recovery of the replacement power costs, there will be no impact on net income.

Uprate and Ratepayer Protection: In March 2004, the PSB approved ENVY's request to increase generation at the Vermont Yankee plant by approximately 110 megawatts, representing a 20 percent increase in plant capacity. The PSB's approval was conditioned on ENVY providing outage protection indemnification ("Ratepayer Protection Proposal" or "RPP") for times the uprate process causes reductions in output that reduce the value of the PPA. The Company's maximum right to indemnification under the RPP is $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). As of September 30, 2006, the Company has collected a nominal amount under the RPP.

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On March 2, 2006, the Nuclear Regulatory Commission ("NRC") gave final approval for the Vermont Yankee plant uprate. On June 8, 2006, the plant received a new output rating of approximately 620 MW. With the decrease in the Company's percent of plant output from 35 to 29 percent, the Company's share of plant output is similar to the amount it received before the uprate process began. If the plant's output rating is reduced (a "derate"), the Company's share of output will also be reduced proportionately under the terms of the PPA. There are three separate issues associated with the uprate and RPP described below.

On March 16, 2006, the Company, Green Mountain Power, ENVY and the DPS filed a settlement with the PSB resolving all issues that were raised in a petition before the PSB regarding the RPP. The Company's share of the settlement is estimated to be $1.6 million including, $0.7 million for recovery of incremental replacement power costs associated with a June 2004 outage at the plant. The remainder is for costs incurred between November 4, 2004 and February 28, 2006, when the plant ran at a reduced level due to the uprate project. Pursuant to the 2005 Rate Order, any reimbursement associated with the June 2004 outage shall be recorded as a regulatory liability for return to ratepayers. The settlement is not effective until the PSB issues a final order. The Company cannot predict the timing or outcome of this matter at this time.

The Company is a party to a PSB Docket that was opened in June 2006 because the DPS was seeking additional ratepayer protections in the event that plant output must be reduced due to failures of the steam dryer. On September 18, 2006, the PSB issued an order requiring ENVY to submit a proposal to provide additional ratepayer protections that will protect Vermont utilities and ratepayers if the plant is forced to reduce output because of uprate-related steam dryer failures. The DPS and ENVY reached an agreement in the compliance filing with the PSB, which will provide protections in the event of a derate. The protections will apply to incremental replacement power costs and will remain in effect for at least two months after the refueling outage during which the plant operates successfully with no steam dryer-related outages or derates. The compliance filing is pending approval before the PSB and is not effective until the PSB issues a final order. The Company cannot predict the outcome of this matter at this time, but it is not expected to have a material impact on the Company's financial position, results of operations or cash flows.

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; another issue is the percentage of power that would be delivered under the PPA in the event of a derate. The Company cannot predict the outcome of this matter at this time.

Operating License: 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 plant in 2007 or 2008 if dry cask storage of its 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 $41 million on an annual basis. Based on this estimate, the Company would require a retail rate increase of 15 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. However, an early shutdown could materially impact the Company's financial position and future results of operations, if the costs are not recovered in retail rates in a timely fashion.

Hydro-Quebec The Company is purchasing power from Hydro-Quebec under the Vermont Joint Owners ("VJO") Power Contract and related contracts negotiated between the Company 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, the remaining VJO participants, must "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.

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In 1994, the Company negotiated a sellback arrangement whereby it received a reduction in capacity costs from 1995 to 1999. In exchange, 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. Hydro-Quebec has not yet exercised these options.

Under the VJO Power Contract, the VJO had elections to change the annual load factor from 75 percent to between 70 and 80 percent five times through 2020, while Hydro-Quebec had elections 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 contract year beginning November 1, 2005, and has made a similar election for the contract year beginning November 1, 2006. The VJO have now used all of their load factor elections. After the contract year ending October 31, 2007, the annual load factor will be at 75 percent for the remainder of the contract, unless all parties to the contract agree to change it or there is a reduction due to the adverse hydraulic conditions described above. Total purchases under the VJO Contract amounted to $16.4 million in the third quarter and $48.2 million in the first nine months of 2006, and $14.2 million in the third quarter and $43.1 million in the first nine months of 2005.

Performance Assurance At September 30, 2006, the Company had posted $5.6 million of collateral under performance assurance requirements for certain of its power contracts, including a $4.5 million letter of credit issued under its $25.0 million revolving credit facility.

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 it is required to post collateral for all net purchase transactions. ISO-New England reviews collateral requirements on a daily basis. As of September 30, 2006, the Company had posted $1.1 million of collateral, of which $1.0 million was above the required amount and is included in Cash and Cash Equivalents. The remaining $0.1 million 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 the end of 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. Collateral requirements under both contracts are reviewed at least weekly. As of September 30, 2006, the Company had posted $4.5 million in the form of a letter of credit for one contract, and none for the second contract. There were no amounts drawn under the letter of credit as of September 30, 2006.

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 to question 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.

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

Cleveland Avenue Property The Cleveland Avenue property in Rutland, Vermont, was used by a predecessor to make gas from coal. Later, the Company sited various operations there. Due to the existence of coal tar deposits, polychlorinated biphenyl contamination and the potential for off-site migration, the Company conducted studies in the late 1980s and early 1990s to quantify the situation. Investigation at the site has continued, including work with the State of Vermont to develop a mutually acceptable solution. In the second quarter of 2006, the Company engaged a consultant to assist Management in updating the cost estimate of remediation for this site due to technological advancement, improved understanding of the site and its contaminants, and the very low likelihood of site redevelopment in the foreseeable future. The consultant's work was performed and completed in the third quarter of 2006. The Company now expects its liability related to remediation of this site to range from a high of $2.3 million to a low of $0.9 million. Management believes that the most likely cost of the remediation effort is $1.5 million, which is $2.5 million less than the previous accrual. The revised cost estimate was based on an engineering evaluation of possible remediation scenarios

and a Monte Carlo simulation. The Monte Carlo simulation is a complex mathematical model using a broad range of possible outcomes and statistical information in determining the outcome with the highest likelihood of occurrence. The assumptions used in the Monte Carlo model require considerable judgment by Management. The decrease from the original cost estimate reflects updated site information, the availability of advanced remediation technology and the Company's intent to voluntarily clean up the site rather than await a state or federal mandate to complete cleanup.

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 assist Management in updating the cost estimate of remediation for 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 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 Company now expects its liability related to remediation of this site to range from a high of $1.3 million to a low of $0.1 million. Management believes that the most likely cost of the remediation effort is $0.6 million, which is $0.7 million less than the previous accrual. The revised cost estimate was based on an engineering evaluation of possible remediation scenarios and a Monte Carlo simulation. As described above, the Monte Carlo model is complex and the assumptions used in the calculations require considerable judgment by Management. The decrease from the original cost estimate reflects the use and specific remediation-related costs for the scenario with the highest likelihood of occurrence. This previously unavailable information replaced scenarios and related remediation costs that were based on the limited site-specific information available before the Company completed a comprehensive site investigation.

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.

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The Company's reserve for environmental matters described above amounted to about $2.1 million as of September 30, 2006 and $5.4 million as of December 31, 2005. The current and long-term portions of the reserve are reflected 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. 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.

In the third quarter of 2006, the Company and DPS reached an agreement that a portion of the reduction in estimated remediation costs should be attributed to ratepayers, and that the Company file an Accounting Order request with the PSB for approval of such treatment. The Company is planning to submit its request for an Accounting Order with the PSB for deferral of $1.6 million of the reduction as a deferred credit for the benefit of ratepayers. In the third quarter of 2006, the Company determined that regulatory treatment for the ratepayer portion was probable and therefore recorded $1.6 million of the $3.2 million reduction in environmental reserves as a deferred credit, included in Other Deferred Credits - Regulatory on the Condensed Consolidated Balance Sheet. The remaining $1.6 million was recorded as a reduction in operating costs, included in Other Operation on the Condensed Consolidated Statement of Income.

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 - ACQUISITIONS AND PENDING ACQUISITIONS

Rochester Electric On September 1, 2006, the Company purchased substantially all of the plant assets and the franchise of Rochester Electric Light and Power Company ("Rochester") for $0.3 million, and began serving Rochester's 900 electric customers as part of its regulated Vermont service territory. Prior to the purchase, Rochester was a privately owned electric utility located in Rochester, Vermont. The two companies agreed to the transaction on April 6, 2006, which required PSB approval. On August 22, 2006, the PSB issued an order approving the transaction, including approval of the Company's request to defer certain incremental transaction costs over a one-year period in its next rate case.

The purchase price included $0.2 million for the net book value of Rochester's retail electric and distribution system and facilities in Rochester, Stockbridge, and Pittsfield, Vermont, and a 0.17 percent interest in the Highgate Converter located in Highgate. These are included in Utility plant ($0.9 million) and Accumulated depreciation ($0.7 million) on the Condensed Consolidated Balance Sheet. The remaining $0.1 million included items of a nominal amount, such as Rochester's 0.10 percent share of the VJO Power Contract with Hydro-Quebec, customer accounts receivable, materials and supplies, and taxes related to the transaction.

Vermont Electric Cooperative On July 27, 2006, the Company entered into an agreement to purchase the assets and franchise territory of the southern Vermont service territory of 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 about 2,700 customers. The purchase price is expected to be $4.0 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. If the transaction is approved, the Company expects a closing in December 2006.

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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.

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 September 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 September 30, 2006	$79,912 825 6,914 464,864	$463 - 93 1,666	- - $(3) 300	$- - - -	(463) - - (2,662)	$79,912 825 7,004 464,168
2005
Revenues from external customers (1) Equity in earnings from affiliates Income from continuing operations Loss from discontinued operations, net of tax Total assets at December 31, 2005	$75,035 485 2,789 - 496,483	$498 - 98 - 1,824	- - $2 - 58,780	- - - $(168) -	$(498) - - - (5,654)	$75,035 485 2,889 (168) 551,433

Nine Months Ended September 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 September 30, 2006	$241,159 1,694 11,412 464,864	$1,382 - 282 1,666	- - $402 300	- - - -	$(1,382) - - (2,662)	$241,159 1,694 12,096 464,168
2005
Revenues from external customers (1) Equity in earnings from affiliates Income from continuing operations Loss from discontinued operations, net of tax Total assets at December 31, 2005	$225,815 1,446 291 - 496,483	$1,421 - 316 - 1,824	- - $1 - 58,780	- - - $(424) -	$(1,421) - - - (5,654)	$225,815 1,446 608 (424) 551,433
(1) Eversant revenue is included in Other Income on the Condensed Consolidated Statements of Income.

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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. 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. 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 2005 results have been reclassified to conform to this presentation.

Our consolidated earnings for the third quarter were $7.0 million, or 66 cents per diluted share of common stock, and $12.1 million, or $1.07 per diluted share of common stock, for the first nine months of 2006. This compares to third quarter consolidated earnings of $2.7 million, or 21 cents per diluted share of common stock, and $0.2 million, or a 1 cent loss per diluted share of common stock, for the first nine months of 2005. Our 2005 results included a $21.8 million pre-tax charge to earnings, or 91 cents per diluted share of common stock, due to the first-quarter 2005 Rate Order, and losses from discontinued operations amounting to $0.2 million, or 1 cent per diluted share of common stock, in the third quarter and $0.4 million, or 3 cents per diluted share of common stock, in the first nine months. The primary drivers of the year-over-year variances are described in detail in Results of Operations.

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Our top priorities are returning to an investment grade credit rating and continuing to improve communications with our Vermont regulators. Our ongoing liquidity and ability to make necessary investments in our electric system in Vermont are dependent on the adequacy of our retail rates to recover costs and our ongoing efforts to control rising costs. On September 11, 2006, we reached a settlement agreement with the DPS on our May 15, 2006 rate case that will, among other things, increase retail rates by 3.73 percent effective January 1, 2007 and provide for an allowed rate of return of 10.75 percent. We later reached an agreement with the DPS on our request for an Accounting Order to defer $4.7 million of incremental replacement power costs associated with a fourth-quarter 2005 scheduled refueling outage at the Vermont Yankee plant. If the Accounting Order settlement and rate case settlement are approved in the fourth quarter of 2006, the combined rate increase, effective January 1, 2007, will be 4.07 percent. PSB approval of the Accounting Order request will also result in a $1.5 million favorable impact in the fourth quarter of 2006 since we will be reversing previously expensed power costs associated with the outage. See Retail Rates below.

Our current credit rating continues to affect our liquidity. Since the second-quarter 2005 downgrade to below investment grade, we have been required to post collateral under performance assurance requirements for certain of our power contracts. In the third quarter of 2006, we issued a $4.5 million letter of credit under our $25.0 million revolving credit facility to provide collateral under one of our power contracts. We have also started to borrow under the credit facility to manage our working-capital requirements. 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, Vermont Yankee or Hydro-Quebec, could have a material detrimental effect on our liquidity without rapid rate relief from our regulators, or supplemental credit facilities.

In addition to investing in our utility infrastructure, we may have opportunities to continue investing in Vermont Transco LLC ("Transco"), a Vermont limited liability company formed by Vermont Electric Power Company, Inc. ("VELCO") and its owners, including us. We have invested a total of $23.3 million in Transco in 2006. Our direct interest is now at 30.28 percent and earns an allowed rate of return of 11.5 percent. See Liquidity and Capital Resources for additional information.

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. The issues that were raised on appeal primarily focused on whether the 2005 Rate Order set rates retroactively without statutory authorization. On July 18, 2006, the Court issued its decision rejecting our appeal. The Court's decision had no effect on our financial condition or results of operations for 2006.

On May 15, 2006, we filed a request for a 6.15 percent rate increase (additional revenue of $16.4 million on an annual basis), to be effective February 1, 2007. On September 11, 2006, we and the DPS reached a settlement on the case, agreeing to a 3.73 percent increase (additional revenue of $9.9 million on an annual basis) effective January 1, 2007. The settlement agreement has been filed with the PSB, which must review and approve it before it can become effective.

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We agreed to a lower rate increase request primarily by reducing our proposed allowed rate of return on common equity from 12 percent to 10.75 percent, and agreeing to separately pursue our request for an Accounting Order to defer incremental replacement power costs associated with a fourth-quarter 2005 scheduled refueling outage at the Vermont Yankee plant.

On November 6, 2006, we and the DPS filed an agreement with the PSB to settle our Accounting Order request. This agreement, if approved, will result in a rate increase of 0.34 percent. If the Accounting Order settlement and the rate case settlement are approved, the combined rate increase, effective January 1, 2007, will be 4.07 percent (additional revenue of about $10.8 million on an annual basis).

Under terms of the Accounting Order settlement, which must be approved by the PSB, we will: 1) establish a regulatory asset for the deferral of $1.5 million (pre-tax) in power costs, which represents the DPS's calculation of incremental replacement power costs during the outage, which will result in a favorable impact in the period approved; and 2) include the regulatory asset in rate base for recovery in rates over a 24-month amortization period beginning January 1, 2007, which will result in a 0.34 percent rate increase as described above. See Power Supply Matters for additional information regarding the Accounting Order request.

We expect the PSB will issue a decision on the rate case settlement and the Accounting Order settlement by mid-December 2006.

LIQUIDITY AND CAPITAL RESOURCES
Liquidity

At September 30, 2006, we had cash and cash equivalents of $3.3 million included in total working capital of $9.8 million. At September 30, 2005, we had cash and cash equivalents of $11.5 million included in total working capital of $81.2 million. Our cash and cash equivalents at September 30, 2005 included $3.1 million from discontinued operations. The primary components of cash from operating, investing and financing activities for both periods are discussed in more detail below.

Operating Activities of Continuing Operations: Operating activities provided $25.0 million for the first nine months of 2006. Net income, when adjusted for depreciation, amortization, deferred income tax and other non-cash income and expense items provided $29.1 million. Additionally, special deposits related to collateral requirements under certain power contracts decreased by $19.1 million because the required amount was lower mostly due to market prices, and we issued a $4.5 million letter of credit. Changes in working capital and other items provided $4.5 million. This was partially offset by $20.8 million in pension trust fund contributions, $5.0 million in postretirement trust fund contributions, and $2.4 million in postretirement and other benefit-related payments, offset by $0.5 million of contributions received from postretirement plan participants.

During the first nine months of 2005, operating activities provided $1.9 million. Net income, when adjusted for depreciation, amortization, deferred income tax and other non-cash income and expense items, provided $30.4 million, including a $21.8 million charge, net of $6.5 million of customer refunds, related to the 2005 Rate Order. Additionally, $21.5 million was used to meet performance assurance requirements under power transaction agreements, $6.3 million was contributed to Pension and Postretirement trust funds and $0.7 million was used by working capital and other items.

Investing Activities of Continuing Operations: Investing activities provided $30.1 million for the first nine months of 2006, including $69.0 million in proceeds from net sales and maturities of available-for-sale securities. We sold $50.0 million of available-for-sale securities for the purchase of shares of our common stock through the tender offer that concluded in April 2006. We used $15.1 million for construction expenditures, $23.3 million for investments in Transco, $0.2 million for the purchase of utility plant and $0.3 million for other investments.

During the first nine months of 2005, investing activities provided $6.0 million, including $12.2 million in proceeds from net sales and maturities of available-for-sale securities, and $5.1 million from discontinued operations, offset by $11.3 million for construction expenditures.

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Financing Activities of Continuing Operations: Financing activities used $58.4 million for the first nine months of 2006, including $51.2 million for the tender offer, $8.0 million for dividends paid on common and preferred stock and $0.8 million for capital lease payments. These items were partially offset by $1.2 million from stock issuance proceeds resulting from stock option exercises, $0.3 million from net borrowings under our revolving credit facility, and $0.1 million from other items.

During the first nine months of 2005, financing activities used $8.7 million, including $9.1 million of common and preferred dividends.

Discontinued Operations: Discontinued operations is related to Catamount which was sold in the fourth quarter of 2005. It provided $0.6 million during the first nine months of 2005.

Available-for-sale Securities: All investments in available-for-sale securities at September 30, 2006 are expected to be redeemed within one year. This includes $6.0 million with original maturities ranging from 90 days to one year, and a $2.9 million security with an original maturity of 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. VELCO, and now Transco, own and operate an integrated transmission system in Vermont over which bulk power is delivered to all electric utilities in the state. We have invested a total of $23.3 million in Transco, including $8.9 million on June 30, $0.4 million on July 31 and $14.0 million on September 29. Our investments in Transco will earn an allowed return of 11.5 percent. Based on current projections, Transco expects to have additional capital needs in the 2007 to 2010 timeframe, but their projections are subject to change based on a number of factors, including revised construction project estimates, timing of regulatory project approvals, and changes in equity to debt ratio. Our investment plans in Transco will be evaluated on a case-by-case basis, and are subject to certain factors including those relating to 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. If, in the fourth quarter of 2006, the PSB approves the rate case and Accounting Order settlements that we reached with the DPS, our retail rates will increase by 4.07 percent beginning January 1, 2007, adding about $10.8 million to annual revenues.

Utility Acquisitions: On September 1, 2006, we completed the purchase of substantially all of the plant assets and franchise of Rochester Electric Light and Power Company ("Rochester") for net book value. Rochester was a privately owned electric utility located in Rochester, Vermont. The purchase price of about $0.3 million included $0.2 million for net book value of utility plant. The purchase added 900 customers to our customer base.

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 about 2,700 customers. The purchase price is expected to be $4.0 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.

While these purchases are not expected to significantly increase earnings, we expect that the consolidation into our existing service territory will provide synergies that enhance service responsiveness and reliability for the combined territories.

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Pension and Other Postretirement Benefits: In September 2006, we made our planned contributions of $9.5 million to our pension and postretirement medical funds. We also made contributions of $16.3 million in the first quarter of 2006. We are currently evaluating the potential impact of the Pension Protection Act of 2006, which was passed into law and signed by the President in August 2006. The new law provides clarity for plan sponsors concerning funding of defined benefit pension plans. It also includes provisions related to defined contribution plans, hybrid plans, nonqualified deferred compensation and health care benefits. The new provisions regarding funding are effective in 2008.

Capital Expenditures: As of September 30, 2006 capital expenditures amounted to $15.1 million. This is consistent with our annual projection of $18.0 million for 2006.

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. Based on our current cash forecasts, we believe the borrowing capacity under the credit facility will likely provide sufficient liquidity at least until the end of 2007, and possibly longer. 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: Scheduled sinking fund payments for the next five years are $0 in 2006 and 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: We have a three-year $25.0 million unsecured revolving-credit facility with a lending institution pursuant to a Credit Agreement dated October 21, 2005. On September 26, 2006, a $4.5 million letter of credit was issued under this facility to support certain power-related performance assurance requirements. It expires on September 25, 2008. Currently no amounts have been drawn down under the letter of credit. At September 30, 2006, we also had $0.3 million of borrowings outstanding under this facility. We expect to make periodic short-term borrowings under the revolving credit facility to manage our working capital requirements

Letters of Credit: In addition to the letter of credit we issued under the credit facility, we have three outstanding unsecured letters of credit, issued by one bank, totaling $16.9 million in support of three separate issues of industrial development revenue bonds totaling $16.3 million. These letters of credit are secured under the Company's first mortgage indenture as required by the bank. At September 30, 2006, there were no amounts outstanding under these letters of credit.

Covenants: At September 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.

Contractual Obligations

There have been no significant changes to the contractual obligations table disclosed in our 2005 Annual Report on Form 10-K.

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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 the 2005 Catamount sale, the major portion of our unregulated businesses. At our own initiation, we are no longer rated by Fitch Ratings.

Performance Assurance
As of September 30, 2006, we had posted $5.6 million of collateral under performance assurance requirements for certain of our power contracts, primarily due to our credit rating, including a $4.5 million letter of credit issued under our $25.0 million revolving credit facility. 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 September 30, 2006, we had posted $1.1 million of collateral, of which $1.0 million was above the required collateral. We post collateral above the required amount to provide flexibility for purchase activity in the wholesale markets.

We are currently selling power in the wholesale market pursuant to two third-party contracts covering periods through the end of 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. Collateral requirements under these contracts are reviewed at least weekly. As of September 30, 2006, we had posted $4.5 million of collateral in the form of a letter of credit for one of the contracts, and none for the second contract. On October 6, 2006, the second contract was amended to provide, among other things, reduced collateral requirements if we meet certain minimum liquidity levels defined as cash and cash equivalents plus the available undrawn portion of any outstanding credit facilities. As of November 7, 2006, our total collateral requirement under the two contracts is estimated to be $5.2 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, and the remaining volume of power to be sold under these contracts, 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 to question 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.

Off-balance sheet arrangements

We do not use off-balance sheet financing arrangements such as securitization of receivables, or obtain access to assets through special purpose entities. We have material power supply commitments, and an indemnification related to the Catamount sale, which are discussed in Note 9 - Commitments and Contingencies. We have letters of credit described above, and we also have vehicle and equipment operating leases. We own equity interests in VELCO and Transco, which require us to pay a portion of the operating costs through transmission billings, and to make additional payments if transmission rates do not provide for full cost recovery. Our equity interests, including VELCO and Transco, are described in Note 2 - Investments in Affiliates.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our financial statements are prepared in accordance with generally accepted accounting principles in the United States ("GAAP"), requiring us to make estimates and judgments that affect reported amounts of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of the Condensed Consolidated Financial Statements. See Critical Accounting Policies and Estimates in Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2005 Annual Report filed on Form 10-K for a discussion of the estimates and judgments necessary in our accounting for regulation, unregulated business, revenues, income taxes, loss accruals, pension and postretirement benefits and other matters. The following is an update to the 2005 Form 10-K.

Regulation We prepare our financial statements in accordance with Statement of Financial Accounting Standards No. 71 ("SFAS No. 71") for our regulated Vermont service territory and FERC-regulated wholesale business. Under SFAS No. 71, we account for certain transactions in accordance with permitted regulatory treatment. Regulators may permit incurred costs, typically treated as expenses by unregulated entities, to be deferred and expensed in future periods when recovered in future revenues. Based on a current evaluation of the factors and conditions expected to impact future cost recovery, we believe future recovery of our regulatory assets in the State of Vermont for our retail and wholesale businesses is probable. In the event that we no longer meet 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 $21.0 million on a pre-tax basis as of September 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 environmental sites where costs for remediation, monitoring and other future activities are probable and can be reasonably estimated. At September 30, 2006, we had a reserve of $2.1 million for three sites that are in various stages of remediation. This compares to a reserve of $5.4 million as of December 31, 2005. To our knowledge, there is no pending or threatened litigation regarding other sites with the potential to cause material expense. No government agency has sought funds from us for any other study or remediation.

We engaged a consultant to assist us in updating the cost estimates for two of the sites, one located in Rutland, Vermont and the other located in Brattleboro, Vermont. The reserve for the third site is less than $0.1 million. The revised cost estimates for the two sites were finalized in the third quarter of 2006, and we now expect our liability related to remediation efforts at these sites to range from a high of $3.6 million to a low of $1.0 million. Management believes that the most likely cost of the remediation effort for the two sites is $2.1 million, which is $3.2 million less than the previous accruals. The revised cost estimates were based on engineering evaluations of possible remediation scenarios at the sites and Monte Carlo simulations. The Monte Carlo simulation is a complex mathematical model using a broad range of possible outcomes and statistical information in determining the outcome with the highest likelihood of occurrence. The assumptions used in the Monte Carlo model require considerable judgment by Management. The decrease from the previous cost estimate for one of the sites reflects updated information, the availability of advanced remediation technology and our intent to voluntarily clean up the site rather than await a state or federal mandate to complete cleanup. The decrease from the previous cost estimate for the other site reflects the use and specific remediation-related costs for the scenario with the highest likelihood of occurrence. See Note 9 - Commitments and Contingencies for additional information. As with any environmental site, unknown conditions or changes in known conditions that were not reasonably predictable at the time that the cost estimates were revised, could materially affect the estimates and actual site remediation costs.

In the third quarter of 2006, we reached an agreement with the DPS that a portion of the reduction in estimated remediation costs should be attributed to ratepayers. We also agreed to request PSB approval of an Accounting Order to defer the ratepayer portion. We plan to submit our request in the near future. In the third quarter of 2006, we determined that regulatory treatment for the ratepayer portion was probable and therefore recorded $1.6 million of the reduction in environmental reserves as a deferred credit on the balance sheet. The remaining $1.6 million was recorded as a reduction in operating costs.

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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. As described above, the Monte Carlo valuation model is complex, and the assumptions used in the calculations require considerable judgment by Management. 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 $0.1 million for all share-based compensation in the third quarter and $0.6 million in the first nine months of 2006. We recorded pre-tax compensation expense of a nominal amount for the third quarter and first nine months of 2005. There are no amounts capitalized for share-based compensation, and the compensation expense is included in the same income statement line item as cash compensation to the same employees.

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. Based on a PSB-approved Accounting Order, we record the change in fair value of power contract derivatives as deferred charges or deferred credits on the 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.

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). 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. Its estimated fair value was an unrealized loss of $3.8 million at September 30, 2006 and $5.0 million at December 31, 2005. We also have a long-term forward contract for the sale of 15 MW per hour through December 31, 2008. The estimated fair value of this derivative is valued using over-the-counter quotations or broker quotes at the end of the reporting period. Its estimated fair value was an unrealized loss of $4.8 million at September 30, 2006 and $12.9 million at December 31, 2005.

RESULTS OF OPERATIONS

The following is a detailed discussion of the results of operations for the three and nine months ended September 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 September 30, 2006 were $7.0 million, or 67 cents per basic and 66 cents per diluted share of common stock. This compares to consolidated earnings of $2.7 million, or 21 cents per basic and diluted share of common stock for the same period in 2005. Third quarter 2005 results included a loss from discontinued operations of $0.2 million, or 1 cent per basic and diluted share of common stock.

Consolidated earnings for the nine months ended September 30, 2006 were $12.1 million, or $1.08 per basic and $1.07 per diluted share of common stock. This compares to consolidated earnings of $0.2 million, or a loss of 1 cent per basic and diluted share of common stock for the same period in 2005. Results for the first nine months 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 $0.4 million, or 3 cents per basic and diluted share of common stock. The table below provides a reconciliation of diluted earnings per share.

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	2006 versus 2005
	Three Months Ended		Nine Months Ended

2005 earnings (loss) per diluted share		$.21		$(.01)

Year-over-Year Effects on Earnings:
Higher resale revenue	.27		.66
Lower transmission costs	.10		.03
Decrease in environmental reserves	.09		.09
CRC higher earnings in 2006 versus 2005	-		.03
Higher (lower) other operating revenue	.03		(.01)
Lower retail revenue (a)	(.02)		(.16)
Higher purchased power costs (a)	(.09)		(.49)
Other variances, net (a)	.06		(.01)
Subtotal		.44		.14
Net impact of 2005 Rate Order charge		-		.91
Discontinued operations - 2005 losses		.01		.03
2006 Earnings per diluted share		$.66		$1.07

(a) Excludes 2005 Rate Order charges for nine months ended September 30, 2005, shown separately above.

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. The amount of resale 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 September 30,				Nine months ended September 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	236,102 236,918 101,686 1,547 576,253 236,231 812,484	240,818 240,678 99,448 1,354 582,298 102,604 - - 684,902	$30,955 27,207 7,882 449 66,493 11,298 - 2,121 $79,912	$31,394 27,408 7,634 394 66,830 6,622 3 1,580 $75,035	717,584 662,473 318,138 4,598 1,702,793 763,850 - 2,466,643	731,807 668,576 305,154 4,029 1,709,566 440,887 - - 2,150,453	$92,856 76,790 25,764 1,331 196,741 38,593 - 5,825 $ 241,159	$95,378 78,303 24,848 1,179 199,708 26,282 (6,194) 6,019 $225,815

Operating revenues for the third quarter and first nine months of 2006 include resale revenue associated with the sale of additional power that we purchased under the long-term contract ("PPA") with VYNPC. The additional power was associated with the Vermont Yankee plant uprate that has increased hourly output by 20 percent. The additional purchases and resulting resale sales began in mid-March when plant output increased due to the power uprate, and ended in mid-September when our entitlement percentage of plant output was changed to reflect the uprate. Under the PPA, we were required to purchase our share of the additional output at market rates. We resold the energy to ISO-New England at the same market rates, since it was not needed to serve our customers.

Operating revenues increased $4.9 million, or 6.5 percent, in the third quarter of 2006 compared to the same period in 2005, due to the following:

Retail sales revenue decreased $0.3 million, primarily due to lower electric sales caused by cooler weather in August. There was also a shift of customers classified as commercial to industrial because usage levels exceeded the consumption amount that would result in commercial classification, which increased revenue from industrial customers.

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Resale sales increased $4.7 million because more mWh were available for resale, including $4.1 million for the resale of additional Vermont Yankee plant output associated with the plant uprate. The remaining $0.6 million increase was due to increased deliveries under the long-term contract with Hydro-Quebec, higher output from our owned and jointly owned generating units, and higher output from Independent Power Producers ("IPP"). Since retail electric sales were slightly lower than the same period last year, the additional power from these sources was available for sale through the ISO-New England wholesale market. The resale revenue associated with these sales was largely offset by the cost to purchase the power as described in Purchased Power below.
Other revenues increased $0.5 million due to third party billings associated with storm restoration performed for other utilities, higher transmission revenue and lower reserves related to a proposed pole attachment tariff settlement.

Operating revenues increased $15.3 million, or 6.8 percent, in the first nine months of 2006 compared to the same period in 2005, due to the following:

Retail sales revenue decreased $3.0 million, including $1.9 million related to the 2.75 percent rate reduction that began in April 2005. The remaining $1.1 million decrease was related to lower electric sales due to milder weather in the period and the shift of commercial customers to industrial classification as described above.
Resale sales increased $12.3 million because more mWh were available for resale, including $8.4 million for the resale of additional Vermont Yankee plant output associated with the uprate. The remaining $3.9 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.
Other revenues decreased $0.2 million primarily related to lower transmission revenue due to annual true-up of estimates under the tariffs, offset by third party billings associated with storm restoration performed for other utilities.

Purchased Power Our power purchases constituted 56 percent of total operating expenses for the third quarter and first nine months of 2006 and 2005. Most of these 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 September 30,				Nine Months Ended September 30,
	mWh		(in thousands)		mWh		(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	453,160 262,891 36,997 753,048 5,902 - - - - 758,950	361,905 193,119 27,071 582,095 57,405 - - - - 639,500	$19,575 16,430 4,106 40,111 (405) (299) 1,540 - 231 $41,178	$14,398 14,165 3,009 31,572 7,073 (299) 1,372 - (79) $39,639	1,300,412 751,577 143,409 2,195,398 34,543 - - - - 2,229,941	1,124,906 604,556 107,383 1,836,845 117,698 - - - - 1,954,543	$54,978 48,228 17,058 120,264 2,247 (897) 4,447 - 588 $126,649	$44,955 43,062 13,035 101,052 13,745 (897) 3,567 2,441 43 $119,951
(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.

Purchased power expense increased $1.5 million, or 3.9 percent, in the third quarter of 2006 compared to the same period in 2005, due to the following:

Long-term purchases increased $8.5 million primarily related to: 1) purchases of Vermont Yankee uprate energy (69,989 mWh for $4.1 million), and higher plant output; 2) more deliveries under the long-term contract with 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.

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Short-term purchases decreased $7.5 million because more power was available from long-term contracts and wholly and jointly owned generating units. The decreased volume of mWh purchases plus certain credits from ISO-New England resulted in a net $0.4 million credit for these purchases in the third quarter of 2006. The credit is primarily related to auction revenue from financial transmission rights ("FTRs"), which are financial instruments that provide an obligation to receive or pay the difference in congestion charges between two locations in the ISO-New England day-ahead energy market. FTRs and related revenue are included in the monthly ISO-New England settlement as purchases and therefore are reflected as part of our purchased power expense. These credits were partly offset by $0.3 million for the purchase of 5,902 mWh as shown in the table above.
Power costs associated with our ownership interests in Maine Yankee, Connecticut Yankee and Yankee Atomic increased $0.2 million due to updated forecasts of decommissioning and other costs associated with these plants. See discussion of Nuclear Generating Companies below.
Other power costs increased $0.3 million, primarily related to regulatory amortizations for 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 $6.7 million, or 5.6 percent, in the first nine months of 2006 compared to the same period in 2005, due to the following:

Long-term purchases increased $19.2 million primarily due to the same factors described above, including: 1) additional purchases of Vermont Yankee uprate energy (145,654 mWh for $8.4 million); 2) more deliveries from Hydro-Quebec; and 3) higher output from IPPs.
Short-term purchases decreased $11.5 million because more power was available from other sources as described above.
Power costs associated with our ownership interests in Maine Yankee, Connecticut Yankee and Yankee Atomic increased $0.9 million for the same reasons described in the third quarter variance above.
Accounting entries related to the 2005 Rate Order had a $2.5 million favorable impact when comparing 2006 versus 2005, since they increased purchased power expense in 2005. The 2005 Rate Order charges were related to Yankee Atomic incremental dismantling costs and Vermont Yankee replacement energy costs resulting from a 2004 unscheduled outage.
Other power costs increased $0.6 million for the same reasons described in the third quarter variance above.

Operating Expenses Operating expenses represent costs incurred to support our core business. Operating expenses increased $1.0 million in the third quarter of 2006 and $7.3 million in the first nine months of 2006 versus comparable periods in 2005. Excluding purchased power expense described above, this amounts to a $0.5 million decrease in the third quarter and a $0.6 million increase in the first nine months of 2006. The primary drivers of the year-over-year variances are described in more detail below.

Production: These expenses are associated with generating electricity from our wholly and jointly owned units. The output from these units is used to serve load or is sold in the wholesale energy markets. These units produced about 12 percent more power in the third quarter and first nine months of 2006 versus the same periods in 2005, primarily due to higher output from our hydro facilities. Production expenses decreased $0.5 million in the third quarter due to lower fuel costs at two of our jointly owned generating units. There was no significant variance for the first nine months of 2006 versus 2005.

Transmission - affiliates: These expenses are associated with transmission of electricity from VELCO and Transco and are primarily related to billings under the Vermont Transmission Agreement ("VTA"). In our discussion of year-over-year variances, we refer to Transco and VELCO as the same entity since VELCO and its owners formed Transco in the second quarter of 2006 to continue its transmission operations. Transmission expenses from affiliates decreased $2.3 million in the third quarter of 2006 primarily due to higher NEPOOL Open Access Transmission Tariff ("NOATT") reimbursements that Transco credits against charges contained in the VTA. The NOATT is the mechanism through which the costs of New England's high voltage (so-called PTF) transmission facilities are collected from load-serving entities using the system and redistributed to the owners of the facilities.

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Transco allocates its monthly cost of service, reduced for NOATT reimbursements and other direct charges, to the Vermont utilities under the VTA. These allocations are based on a formula representing each utility's Vermont load share and other factors, which for us amounts to about 42 percent. The NOATT reimbursements for the tariff year beginning July 1, 2006 are based on Transco's projected annual cost of service for 2006, but are paid out each month as a fixed percentage of the actual total monthly NOATT collections. During the summer months, NEPOOL loads are higher, yielding higher NOATT collections, which result in higher reimbursements to Transco.

NOATT reimbursements for the tariff year beginning July 1, 2005 included only those PTF facilities in service by December 31, 2004. The NOATT was modified effective July 1, 2006 to include facilities projected to be placed in service during the current calendar year (2006), and those in service in prior years. The tariff modifications include a provision to true-up the estimate of current year costs by comparing the projected annual cost of service to the actual cost of service, with the difference plus interest reflected in the rate for the next tariff year. Transco's transmission construction activity included significant project additions in 2005 and 2006, including the projected completion of a portion of the so-called Northwest Reliability Project, which is expected to be completed in part by the end of 2006. Therefore, Transco's reimbursements increased significantly for the tariff year beginning July 1, 2006.

In the third quarter of 2006, Transco's NOATT reimbursements were higher than its cost of service, partly due to the inclusion of the Northwest Reliability Project in reimbursements. Therefore, the net difference was passed on to us under the VTA. Our share amounted to a $2.0 million reimbursement, which was recorded as a reduction in transmission expense for the quarter. This compares to a $0.3 million charge under VTA for the same period in 2005.

Transmission expenses from affiliates for the first nine months of 2006 decreased $1.5 million primarily due to our share of NOATT reimbursements, offset by an increase in Transco's cost of service due to project additions in 2005 and a change in depreciation.

Transmission - other: These expenses are associated with our costs related to transmission of electricity. These transmission expenses increased $0.6 million in the third quarter and $1.0 million in the first nine months of 2006. The increase in both periods was primarily related to higher charges for reliability planning, load dispatch and market facilitation.

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. Other operation expenses decreased $9.4 million in the first nine months of 2006 primarily due to first-quarter 2005 Rate Order charges of $10.7 million. The remaining $1.3 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. These unfavorable variances were partly offset by a third-quarter 2006 reduction in environmental reserves based on revised cost estimates, adjustments and regulatory amortizations beginning in April 2005 per the 2005 Rate Order and bondholder consent fees in 2005. 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. There was no significant variance for the third quarter of 2006 versus the same period in 2005.

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. Maintenance expenses increased $2.9 million in the first nine months of 2006 due to higher storm restoration costs in the first quarter 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 partly offset by the favorable impact of regulatory amortizations. There was no significant variance for the third quarter of 2006 versus the same period in 2005.

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.

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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. Other Income and Deductions increased $0.3 million in the third quarter and $2.2 million in the first nine months of 2006 versus the same periods in 2005 due to the following.

Equity in earnings of affiliates: These are related to our equity investments including VELCO, Transco and VYNPC. Equity in earnings increased $0.3 million in the third quarter and the first nine months of 2006, primarily related to investments that we made in Transco in the second quarter of 2006.

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. Other income increased $1.6 million in the first nine months of 2006, including first-quarter 2005 Rate Order charges of $0.8 million. The remaining $0.8 million increase was 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 certain deferred Vermont Yankee costs. There was no significant variance for the third quarter of 2006 versus the same period in 2005.

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. Other deductions decreased $1.0 million in the first nine months of 2006, including $0.4 million related to a first-quarter 2005 Rate Order disallowance of a portion of Vermont Yankee deferred costs. The remaining $0.6 million decrease is primarily related to the 2005 impairment and realized losses associated with certain available-for-sale debt securities that were sold earlier than planned. There was no significant variance for the third quarter of 2006 versus the same period in 2005.

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. Interest expense decreased $1.2 million in the first nine months of 2006 primarily related to first-quarter 2005 Rate Order charges to adjust carrying costs associated with the recalculation of overearnings for 2001 - 2003. There was no significant variance for the third quarter of 2006 versus the same period in 2005.

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
September 30,
2006                  2005

Nine Months Ended
September 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 interest expense

Net loss from discontinued operations

$-
  -
  -

-
-
-
  -
  -
  -

$-

$-
  (83)
   83

27
1,218
(1,863)
    634
      16
    267

$(168)

$-
  -
  -

-
-
-
  -
  -
  -

$-

$-
  (275)
   275

1,386
2,832
(5,115)
    669
   (228)
   471

$(424)

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POWER SUPPLY MATTERS
Our material power supply contracts are principally with Hydro-Quebec and VYNPC. These contracts comprise the majority of our total annual energy (mWh) purchases. The VYNPC contract is priced well below current market prices. If one or both of these sources becomes unavailable for a period of time, absent alternative supply arrangements, there could be exposure to spot market power prices that could materially affect net power costs.

We constantly monitor, and adapt to, changes to New England wholesale power markets. ISO-New England implemented Standard Market Design ("SMD"), a significant step to restructuring the wholesale energy markets in the Northeast, in March 2003. SMD includes day-ahead and real-time energy markets, and location-specific energy pricing, depending in part on the existence of transmission constraints as well as on the concept of location-specific marginal losses. We have responded to SMD by generally using the day-ahead market to clear the majority of our load and generation, including generation resources that we self-schedule, with any remaining resources and residual load settling in the real-time market.

In June 2006, the FERC issued an Order approving a contested settlement related to the implementation of locational installed capacity ("LICAP"), a new system of capacity payments to generators in New England. The FERC Order adopts the forward capacity market ("FCM") as a replacement to LICAP. Unless the FERC reverses its decision, FCM will begin on June 1, 2010, and will establish auctions designed to procure capacity three or more years ahead of time with a one- to five-year commitment period. FCM includes a locational mechanism to establish separate zones for capacity when transmission constraints are found to exist. The FERC Order also provides for a transition period from December 1, 2006 through May 31, 2010 during which time-fixed payments will be made to generators at rates established in the agreement. Since we expect to have committed resources to meet our capacity requirements through 2011, we do not expect this mechanism to materially increase our costs through 2011, but we are not able to determine whether FCM will ultimately increase our costs due to market factors.

Hydro-Quebec We purchase 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, 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 1994, we negotiated a sellback arrangement whereby we received a reduction in capacity costs from 1995 to 1999. In exchange, 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 our 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. Hydro-Quebec has not yet exercised these options.

Under the VJO Power Contract, the VJO had elections to change the annual load factor from 75 percent to between 70 and 80 percent five times through 2020, while Hydro-Quebec had elections 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 contract year beginning November 1, 2005, and has made a similar election for the contract year beginning November 1, 2006. The VJO have now used all of their load factor elections. After the contract year ending October 31, 2007, the annual load factor will be at 75 percent for the remainder of the contract, unless all parties agree to change it or there is a reduction due to the hydraulic conditions described above.

Vermont Yankee As of September 15, 2006, we have a 29 percent entitlement in Vermont Yankee plant output sold by ENVY to VYNPC. Our entitlement was reduced from 35 percent due to the plant power output uprate described below, but we are still purchasing about 180 MW of plant output. These purchases are made through the PPA with VYNPC. One remaining secondary purchaser continues to receive a small percentage (less than 0.2 percent) of our entitlement. ENVY has no obligation to supply energy to VYNPC over the amount the plant is

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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 section below provides a more detailed discussion of items of interest related to our power purchases from VYNPC.

October 2005 Refueling Outage: 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. The price for replacement power was significantly higher than what was being recovered in retail rates. We recorded net incremental replacement power costs of $5.4 million in the fourth quarter of 2005. On December 23, 2005, we filed a request for an Accounting Order from the PSB to defer $3.6 million for recovery in our next rate proceeding. Our request included $4.7 million for net incremental replacement power costs above those already embedded in retail rates, and application of the $1.1 million credit we received through a VYNPC power bill 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 expected from 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. The PSB's review of the Accounting Order request was subsequently combined with our May 15, 2006 rate increase request. On September 11, 2006, we reached a settlement agreement with the DPS on our rate increase request, but it did not resolve our Accounting Order request. The rate case settlement did include application of the $1.1 million received through the VYNPC power bill in 2005, so we and the DPS filed amended testimony with the PSB on the Accounting Order request, and we revised our request from $3.6 million to $4.7 million.

On November 6, 2006, we and the DPS filed an agreement with the PSB to settle our Accounting Order request. Under terms of the Accounting Order settlement, which requires PSB approval, we will: 1) establish a regulatory asset for the deferral of $1.5 million (pre-tax) in power costs, which represents the DPS's calculation of incremental replacement power costs during the outage; and 2) include the regulatory asset in rate base for recovery in rates over a 24-month amortization period beginning January 1, 2007. If the PSB approves the Accounting Order settlement in the fourth quarter of 2006 it will result in a $1.5 million (pre-tax) favorable impact in the fourth quarter of 2006 since the power costs were previously expensed in 2005, and a 0.34 rate increase as described in Retail Rates above. We expect a PSB decision on the Accounting Order settlement by mid-December 2006.

2007 Scheduled Refueling Outage: The next refueling outage at the Vermont Yankee plant is scheduled to begin in mid-May 2007. In order to meet our load requirements, our practice has been to purchase firm replacement power when the plant is not operating. At this time, we have not entered into forward power purchase contracts for the 2007 scheduled refueling outage, but we expect to do so before the outage begins.

Forced Outage Insurance: On October 3, 2006, we purchased forced outage insurance for $1.3 million, to cover additional costs, if any, of obtaining replacement power from other sources if the Vermont Yankee plant experiences unplanned outages between January 1 and December 31, 2007. The coverage applies to unplanned outages of up to 30 consecutive calendar days per outage event, and provides for payment to us of the difference between hourly spot market prices and the PPA price when the spot price is above the $40/mWh PPA price. Under this coverage, we will receive payments on claims within 30 days of submitting proof of loss claims. The total maximum coverage is $10.0 million, with a $1.0 million total deductible. The September 11, 2006 rate case settlement, if approved, includes a provision for deferral of the difference between the actual policy premium and the amount to be recovered in rates (about $1.8 million). The $0.5 million deferral is to be used to offset the deductible or other uninsured costs associated with an unexpected outage or derate at the Vermont Yankee plant.

Uprate and Ratepayer Protection: In March 2004, the PSB approved ENVY's request to increase generation at the Vermont Yankee plant by approximately 110 megawatts, representing a 20 percent increase in plant capacity. The PSB's approval was conditioned on ENVY providing outage protection indemnification ("Ratepayer Protection Proposal" or "RPP") for times the uprate process causes reductions in output that reduce the value of the PPA. Our maximum right to indemnification under the RPP is $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). As of September 30, 2006, we have collected a nominal amount under the RPP.

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On March 2, 2006, the Nuclear Regulatory Commission ("NRC") gave final approval for the Vermont Yankee plant uprate. On June 8, 2006, the plant received a new output rating of approximately 620 MW. With the decrease in our percent of plant output from 35 to 29 percent, our share of plant output is similar to the amount we received before the uprate process began. If the plant's output rating is reduced (a "derate"), our share of output will also be reduced proportionately under the terms of the PPA. There are three separate issues associated with the uprate and RPP described below.

On March 16, 2006, we, Green Mountain Power, ENVY and the DPS filed a settlement with the PSB resolving all issues that were raised in a petition before the PSB regarding the RPP. Our share of the settlement is estimated to be $1.6 million, including $0.7 million for recovery of incremental replacement power costs associated with a June 2004 outage at the plant. The remainder is for costs incurred between November 4, 2004 and February 28, 2006 when the plant ran at a reduced level due to the uprate project. Pursuant to the 2005 Rate Order, any reimbursement associated with the June 2004 outage shall be recorded as a regulatory liability for return to ratepayers. The settlement is not effective until the PSB issues a final order. We cannot predict the timing or outcome of this matter at this time.

We are a party to a PSB Docket that was opened in June 2006 because the DPS was seeking additional ratepayer protections in the event that plant output must be reduced due to failures of the steam dryer. On September 18, 2006, the PSB issued an order requiring ENVY to submit a proposal to provide additional ratepayer protections that will protect Vermont utilities and ratepayers if the plant is forced to reduce output because of uprate-related steam dryer failures. The DPS and ENVY reached an agreement in the compliance filing with the PSB, which will provide protections in the event of a derate. The protections will apply to incremental replacement power costs and will remain in effect for at least two months after the refueling outage during which the plant operates successfully with no steam dryer-related outages or derates. The compliance filing is pending approval before the PSB and is not effective until the PSB issues a final order. While we cannot predict the outcome of this matter at this time, we do not believe there could be an adverse outcome.

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; another issue is the percentage of power that would be delivered under the PPA in the event of a derate. We cannot predict the outcome of this matter at this time.

Operating License: 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. Also see Recent Energy Policy Initiatives below. Prior to these actions, ENVY had announced that it could be required to shut down the plant in 2007 or 2008 if dry cask storage of its 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 $41 million on an annual basis. Based on this estimate, we would require a retail rate increase of 15 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. However, an early shutdown could materially impact our financial position and future results of operations, if the costs are not recovered in retail rates in a timely fashion.

Independent Power Producers: 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.

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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 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 was needed for FERC to relicense the facilities for 30 years. The agreement stipulates that subject to various conditions, we must begin decommissioning the Peterson Dam in 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, the FERC issued a 30-year license for the four dams, including Peterson Dam. 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. In November 2005, the FERC denied rehearing requests and clarified certain terms of the license. In January 2006, we and the VANR filed timely appeals in federal court. The federal court has stayed all action on the appeals until completion of the proceedings before the PSB and further filings by the parties. The 30-year license remains in effect during such appeals.

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. On October 13, 2006, the PSB held an oral argument, and has stated that it intends to issue an order by the end of November. 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 these costs will continue to be recovered through the regulatory process.

Our share of Maine Yankee, Connecticut Yankee and Yankee Atomic estimated costs are adjusted when revised estimates are provided by the companies. At September 30, 2006, our obligations related to these plants amounted to $3.7 million for Maine Yankee, $8.8 million for Connecticut Yankee and $3.6 million for Yankee Atomic (including $0.3 million for incremental decommissioning costs that we already paid and are now recovering 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.

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On September 30, 2006, United States Court of Federal Claims Senior Judge Merow issued a favorable ruling for Maine Yankee, Connecticut Yankee and Yankee Atomic in the DOE litigation. Maine Yankee was awarded $75.8 million in damages through 2002, Connecticut Yankee was awarded $34.1 million through 2001, and Yankee Atomic was awarded $32.9 million through 2001. The three companies had claimed actual damages through the same periods in the amount of $78.1 million for Maine Yankee, $37.7 million for Connecticut Yankee and $60.8 million for Yankee Atomic. Most of the reduction in the claimed losses related to disallowed wet pool operating expenses, which the Court felt the companies would have incurred notwithstanding the DOE breach.

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

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

In July 2006, Connecticut Yankee determined that it could no longer conclude that it is probable it will recover $10.0 million of decommissioning costs in its wholesale decommissioning charges. Therefore, Connecticut Yankee recorded a $6.0 million after-tax reduction in its equity in the second quarter of 2006. We recorded our share of the write-off, $0.1 million after-tax, in the second quarter of 2006.

On August 15, 2006, a proposed settlement of Connecticut Yankee's FERC Rate Case was filed with the FERC. Among the notable provisions of the settlement are the following: 1) the decommissioning collections schedule will be reduced to reflect the lower escalation factor starting January 1, 2007; 2) any claims of imprudence made in the docket against Connecticut Yankee in its decommissioning effort are resolved with no finding of imprudence; 3) the decommissioning collections schedule will credit ratepayers with the $15.0 million settlement payment from Bechtel to Connecticut Yankee in 2007, 2008 and 2009; 4) the decommissioning collections schedule will be reduced by $10.0 million as part of a budget incentive plan wherein timely license termination performance by Connecticut Yankee will offset some of the reduction; 5) the decommissioning collections schedule will be extended from 2010 to December 2015; 6) the decommissioning collections schedule will be subject to an investment earnings tracking mechanism for performance greater than or less than certain targets; and 7) Connecticut Yankee will resume reasonable payment of dividends to its stockholders subject to certain incentive target balances. This settlement, if approved by the FERC, will, among other things, result in lower decommissioning expenses for us over the near-term.

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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 this settlement is 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 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 were to disallow cost recovery in wholesale rates, it is anticipated that the PSB would disallow these costs for recovery in retail rates as well. The FERC ruling on the filed settlement is expected by the end 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 2007, the remaining on-site function will be to operate the Independent Spent Fuel Storage Installation.

On May 1, 2006, Yankee Atomic filed with the FERC a settlement agreement among all of the parties. On July 31, 2006, the FERC issued an Order approving the settlement agreement that reduces Yankee Atomic's November 2005 decommissioning cost estimate by $32.0 million and increases the number of years for revenue collection from 2010 to 2014 in order to provide near-term rate relief. Under the approved settlement agreement, Yankee Atomic agreed to reduce its revenue requirements by $79.0 million for the period 2006-2010 and to increase its revenue requirements by $47.0 million for the period 2011-2014. The revision includes adjustments for contingencies, projected escalation and certain decontamination and dismantling expenses. The approved settlement also provides for reconciling and adjusting future charges based on actual decontamination and dismantling expenses and the decommissioning trust fund's actual investment earnings. We believe that our share of the increase in decommissioning costs will ultimately be recovered from customers.

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, 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 trial is expected to be held in August 2008. 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 an additional 20 years, extending the license 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. 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 1.4 MW, and we would be obligated to pay our ownership share of the related costs.

DIVERSIFICATION

CRC's earnings were $0.1 million in the third quarter of 2006 and $0.7 million in the first nine months of 2006. This compares to earnings of $0.1 million in the third quarter of 2005 and $0.3 million in the first nine months of 2005. The $0.4 million increase in the first nine months 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:

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Power Supply Requirements - Act 61 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. In September 2006, the PSB adopted a rule to implement the SPEED program.

In the first quarter of 2006, we agreed in principle to purchase all of the output (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.

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 alternative form of regulation for our operations.

Under alternative regulation, rate changes could occur under the terms of an alternative regulation plan. The PSB recently approved an alternative regulation plan for Vermont Gas Systems, and the DPS recently agreed to a similar plan for Green Mountain Power ("GMP"). The PSB is expected to rule on the GMP Alternative Regulation Plan before January 2007, although by law the PSB has until April to issue its ruling. GMP's proposed plan covers the three years 2007 to 2009. A prominent part of the plan is a power supply adjustment mechanism that will allow GMP to adjust rates on a quarterly basis to reflect power supply cost changes in excess of a certain amount per quarter. GMP's proposed plan proposes an earnings sharing mechanism to allow sharing of all or a portion of earnings in excess of its allowed return on equity, and to recover earnings shortfalls in excess of a certain amount below its allowed return on equity. The GMP plan also proposes other incentives and opportunities for the utility to improve performance and earnings.

We are still analyzing the implications of the GMP's proposed plan. If we conclude that an acceptable alternative regulation plan is feasible, we would file a petition asking the PSB for approval of the plan. While the PSB has a year to consider the plan, expedited approval could eliminate the need to file a rate case in 2007.

In 2006, the Vermont Legislature passed Act 208, "Vermont Energy Security and Reliability Act" ("Act 208"), a law that includes four 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 enable 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 several ideas including: 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.

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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.

4. Public Engagement Process - The new law directs the DPS and the legislature's Joint Energy Committee to "conduct a comprehensive statewide public engagement process on energy planning, focused on electric energy supply choices facing the state beginning in 2012". The DPS recently chose a consultant who will actually implement the outreach effort through workshops, polling and public hearings. The DPS intends to use the outcome of these discussions to update the 20-Year Electric Plan to provide direction to the state's utilities and inform the PSB of power supply decisions. This process is expected to begin soon and will run at least through the end of 2007.

In 2006, the Vermont legislature established an additional procedure for authorization of Vermont Yankee's continued operation after 2012 ("Act 160"). Act 160 establishes that the Legislature and the PSB will each have a role in deciding whether the Vermont Yankee plant in Vernon will be allowed to operate after its current license expires in 2012. Under a law passed in 2005, owners of the plant need permission from the Vermont General Assembly and the PSB to store any nuclear waste generated from operations at the site after March 21, 2012. That is the date when federal and state licenses expire. In Vermont, the "license" is a certificate of public good issued by the PSB. As enacted, both the Legislature and PSB have a voice in assuring that relicensing and continued on-site storage of spent nuclear fuel "will promote the general welfare" of the state, but approval of state relicensing counts as approval for added storage. The bill allows the state relicensing process to go forward if the Legislature fails to act within the next two years. Accordingly, if the Legislature fails to act by 2008, the PSB may thereafter issue a new certificate of public good that authorizes both continued plant operation and on-site storage of spent fuel after March 2012.

In 2006, the Vermont legislature also passed the Regional Greenhouse Gas Initiative ("Act 123"). Act 123 authorizes the Vermont Agency of Natural Resources to cooperate with other signatories to a regional memorandum of understanding to establish a carbon cap and trade system intended to reduce the amount of carbon emissions released by electric generating stations. The program, slated to begin in 2009, will include an allocations process by which the credits earned by Vermont's relatively "green" power supply will be distributed among participants in the electrical supply industry according to the goals of lowering costs, improving efficiency and reducing the carbon emissions profile of the state. Vermont expects to receive allowances equal to 1.28 million tons of emissions worth an estimated $2 million to $5 million annually.

We have a statutory duty to serve our customers with electric power when the need arises. We are pursuing two initiatives that are intended to help facilitate the state's public engagement process described above. First, we recently completed work on an energy supply decision framework to help coordinate our integrated resource planning responsibilities with the state's on-going energy policy deliberations. This effort is designed to provide a way to help compare and contrast attributes, costs and other characteristics of various power resource decisions, and sets out a timeline to track progress. The second initiative is a study of the possibility of building new base load generation in Vermont. In concert with other members of the E-23 Group, an organization of the state's electric utilities, we expect to contract with a consultant for an initial feasibility study for completion in early 2007.

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

RECENT ACCOUNTING PRONOUNCEMENTS

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 September 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 September 30, 2006 - unrealized loss	$(12,935) 8,144 $(4,791)	$(4,977) 1,151 $(3,826)
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	$(6,744) $(2,839)	$(7,163) $(1,834)

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 September 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").

We will not be able to conclude that our disclosure controls and procedures are effective until the material weakness has been successfully remediated. 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 were no changes in our internal control over financial reporting during the first nine months of 2006, except for the steps we are taking to remediate the material weakness described below.

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

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

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Our remediation plan has not been fully implemented as of September 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 6.		Exhibits.
	(a)		List of Exhibits
			10.25.6	Amendment to the Power Contract between the Company and Yankee Atomic Electric Company dated October 1, 1980.
			10.25.7	Amendment No. 3 to the Power Contract between the Company and Yankee Atomic Electric Company dated April 1, 1985.
			10.25.8	Amendment No. 8 to the Power Contract between the Company and Yankee Atomic Electric Company dated June 1, 2003.
			10.25.9	Amendment No. 9 to the Power Contract between the Company and Yankee Atomic Electric Company dated November 17, 2005.
			10.25.10	Amendment No. 10 to the Power Contract between the Company and Yankee Atomic Electric Company dated April 14, 2006.
			A 10.95	2000 Stock Option Plan for Key Employees. (Previously filed as Schedule A, Form DEF 14A - Proxy Statement, March 28, 2000, File No. 1-8222)
			A 10.99	2002 Long-Term Incentive Plan. (Previously filed as Schedule A, Form DEF 14A - Proxy Statement, March 29, 2002, File No. 1-8222)
			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 November 8, 2006

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EXHIBIT INDEX
Exhibit Number	Exhibit Description
10.25.6	Amendment to the Power Contract between the Company and Yankee Atomic Electric Company dated October 1, 1980.
10.25.7	Amendment No. 3 to the Power Contract between the Company and Yankee Atomic Electric Company dated April 1, 1985.
10.25.8	Amendment No. 8 to the Power Contract between the Company and Yankee Atomic Electric Company dated June 1, 2003.
10.25.9	Amendment No. 9 to the Power Contract between the Company and Yankee Atomic Electric Company dated November 17, 2005.
10.25.10	Amendment No. 10 to the Power Contract between the Company and Yankee Atomic Electric Company dated April 14, 2006.
A 10.95	2000 Stock Option Plan for Key Employees. (Previously filed as Schedule A, Form DEF 14A - Proxy Statement, March 28, 2000, File No. 1-8222)
A 10.99	2002 Long-Term Incentive Plan. (Previously filed as Schedule A, Form DEF 14A - Proxy Statement, March 29, 2002, File No. 1-8222)
31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Page 59 of 59

CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands, except share data)
	(unaudited) September 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	$522,257 232,137 290,120 11,243 988 302,351	$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 ($3,726 in 2006 and $4,063 in 2005) Millstone decommissioning trust fund Available-for-sale securities Other Total investments and other assets	39,204 1,626 5,110 - 6,901 52,841	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 ($3,001 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 Assets held for sale Other current assets Total current assets	3,314 8,926 983 28 23,141 76 13,249 5,300 7,402 3,513 388 750 67,070	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	22,427 12,573 6,906 41,906 $464,168	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 59
CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands, except share data)
	(unaudited) September 30, December 31, 2006 2005
CAPITALIZATION AND LIABILITIES Capitalization Common stock, $6 par value, 19,000,000 shares authorized, 12,371,215 shares issued and 10,121,240 shares outstanding at September 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	$74,189 53,978 (351) - (51,186) 96,400 173,030 8,054 3,000 115,950 5,631 305,665		$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 3,306 10,659 11,050 2,161 2,113 2,326 2,978 1,614 20,088 57,295		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	29,762 3,815 12,851 2,907 6,882 7,003 14,006 23,982 101,208 $464,168		28,647 4,099 14,670 4,059 25,436 13,414 15,424 28,528 134,277 $551,433

	Three Months Ended September 30, 2006 2005		Nine Months Ended September 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 interest expense Net loss from discontinued operations	$- - - - - - - - - $-	$- (83) 83 27 1,218 (1,863) 634 16 267 $(168)	$- - - - - - - - - $-	$- (275) 275 1,386 2,832 (5,115) 669 (228) 471 $(424)

	Fair value of debt securities at contractual maturity dates
Debt Securities	Less than 1 year $5,985	1 to 5 years $2,941	5 to 10 years -	After 10 years -	Total $8,926

	Equity Securities		Debt Securities
	Fair Value	Unrealized Losses	Fair Value	Unrealized Losses
Less than 12 months 12 months or more Total	$11 125 $136	$- (7) $(7)	$339 338 $677	$(3) (12) $(15)