CENTRAL VERMONT PUBLIC SERVICE CORPORATION

10-Q 1 fnl10q.htm FORM 10-Q PERIOD ENDED SEPTEMBER 30, 2005 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, 2005

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

For the transition period from _______ to _______

Commission file number 1-8222

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

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

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

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

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange 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, 2005 there were 12,283,405 outstanding shares of Common Stock, $6 Par Value.

Page 1 of 65

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Form 10-Q - 2005

Table of Contents

		Page
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Statements of Income (unaudited) for the three and nine months ended September 30, 2005 and 2004	3
	Condensed Consolidated Statements of Comprehensive Income (unaudited) for the three and nine months ended September 30, 2005 and 2004	4
	Condensed Consolidated Balance Sheets as of September 30, 2005 (unaudited) and December 31, 2004	5
	Condensed Consolidated Statements of Retained Earnings (unaudited) for the three and nine months ended September 30, 2005 and 2004	7
	Condensed Consolidated Statements of Cash Flows (unaudited) for the nine months ended September 30, 2005 and 2004	8
	Notes to Condensed Consolidated Financial Statements	9
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	34
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	62
Item 4.	Controls and Procedures	62
PART II	OTHER INFORMATION	63
SIGNATURES		64
EXHIBIT INDEX		65

Page 2 of 65

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (unaudited) (in thousands, except per share data)
	Three Months Ended September 30 2005 2004		Nine Months Ended September 30 2005 2004
Operating Revenues	$75,013	$72,740	$225,750	$224,489
Operating Expenses Operation Purchased Power - affiliates Purchased Power - other sources Production and Transmission Other Operation Maintenance Depreciation Other taxes, principally property Income tax expense (benefit) Total Operating Expenses	15,720 23,919 6,715 9,808 4,820 4,099 3,492 2,448 71,021	16,363 19,264 6,032 10,952 4,306 3,972 3,396 2,669 66,954	47,380 72,571 20,299 43,843 13,132 12,254 10,417 (956) 218,940	44,226 83,688 18,800 32,832 12,149 12,044 10,168 1,428 215,335
Operating Income	3,992	5,786	6,810	9,154
Other Income and (Deductions) Equity in earnings of affiliates Equity in earnings of non-utility investments Allowance for equity funds during construction Gain on sale of non-utility investments Other income Other deductions Benefit (provision) for income taxes Total Other Income and (Deductions)	485 27 19 - 1,474 (1,557) 539 987	410 1,145 47 1,980 1,237 (1,826) (527) 2,466	1,446 1,386 51 - 4,730 (7,147) 507 973	881 3,747 95 1,980 5,686 (5,069) (1,712) 5,608
Total Operating and Other Income	4,979	8,252	7,783	14,762
Interest Expense Interest on long-term debt Other interest Allowance for borrowed funds during construction Total Interest Expense	2,078 186 (6) 2,258	2,049 164 (18) 2,195	5,792 1,823 (16) 7,599	7,071 164 (38) 7,197
Income from continuing operations Income from discontinued operations, net of tax (including gain on disposal of $12,334 in 2004) Net Income Dividends on preferred stock	2,721 - 2,721 92	6,057 8 6,065 259	184 - 184 276	7,565 12,354 19,919 775
Earnings (Loss) available for common stock	$2,629	$5,806	$(92)	$19,144
Per Common Share Data: Basic: Earnings (loss) from continuing operations Earnings from discontinued operations Earnings (loss) per share Diluted: Earnings (loss) from continuing operations Earnings from discontinued operations Earnings (loss) per share	$.21 - $.21 $.21 - $.21	$.48 - $.48 $.47 - $.47	$(.01) - $(.01) $(.01) - $(.01)	$.56 1.02 $1.58 $.55 1.01 $1.56
Average shares of common stock outstanding - basic Average shares of common stock outstanding - diluted Dividends per share of common stock	12,276,642 12,365,263 $.23	12,138,847 12,296,739 $-	12,251,944 12,251,944 $.92	12,105,248 12,276,905 $.69

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

Page 3 of 65

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (in thousands) (unaudited)
	Three Months Ended September 30 2005 2004		Nine Months Ended September 30 2005 2004
Net Income	$2,721	$6,065	$184	$19,919
Other comprehensive income, net of tax: Foreign currency translation adjustments Gain (loss) on investments: Unrealized holding gain (loss) Realized (gain) loss	(197) 71 (16)	(330) 326 -	(139) 81 150	(608) (144) -
Comprehensive Income	$2,579	$6,061	$276	$19,167

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

Page 4 of 65

CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands)
			(unaudited) September 30 December 31 2005 2004
ASSETS Utility plant, at original cost Less accumulated depreciation Net utility plant Construction work-in-progress Nuclear fuel, net Total utility plant			$509,383 222,413 286,970 9,380 1,297 297,647			$502,551 213,719 288,832 9,657 971 299,460
Investments and other assets Investment in affiliates Non-utility investments Non-utility property, less accumulated depreciation Millstone decommissioning trust fund Available-for-sale securities Other Total investment and other assets			15,898 35,699 2,524 4,801 8,920 6,388 74,230			16,070 25,670 2,936 4,721 21,918 6,145 77,460
Current assets Cash and cash equivalents Available-for-sale securities Restricted cash Special deposits Notes receivable Accounts receivable, less allowance for uncollectible accounts ($1,406 in 2005 and $1,886 in 2004) Accounts receivable - affiliates, less allowance for uncollectible accounts ($576 in 2005 and $484 in 2004) Unbilled revenues Materials and supplies, at average cost Prepayments Other current assets Total current assets			11,536 18,600 22,938 21,532 4,526 20,507 239 13,671 3,143 9,362 2,390 128,444			11,722 19,262 2,000 - 29,182 20,832 909 17,693 3,435 6,326 2,213 113,574
Deferred charges and other assets Regulatory assets Other deferred charges - regulatory Other Total deferred charges and other assets TOTAL ASSETS			27,681 23,536 7,511 58,728 $559,049			13,141 36,945 6,183 56,269 $546,763
The accompanying notes are an integral part of these consolidated financial statements Page 5 of 65
CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands)
			(unaudited) September 30 December 31 2005 2004
CAPITALIZATION AND LIABILITIES Capitalization Common stock, $6 par value, authorized 19,000,000 shares (issued and outstanding 12,277,005 and 12,193,093) Other paid-in capital Accumulated other comprehensive loss Deferred compensation - employee stock ownership plans Retained earnings Total common stock equity Preferred and preference stock Preferred stock with sinking fund requirements Long-term debt Capital lease obligations Total capitalization			$73,657 52,362 (38) (7) 89,147 215,121 8,054 5,000 139,910 6,336 374,421				$73,153 51,964 (130) (36) 100,512 225,463 8,054 6,000 126,750 7,094 373,361
Current liabilities Current portion of long-term debt Current portion of preferred stock Accounts payable Accounts payable - affiliates Accrued income taxes Accrued interest Dividends declared Nuclear decommissioning costs Other current liabilities Total current liabilities			681 1,000 4,272 9,933 712 2,093 2,824 4,466 21,281 47,262				- 2,000 6,478 10,764 573 323 - 5,436 20,331 45,905
Deferred credits and other liabilities Deferred income taxes Deferred investment tax credits Nuclear decommissioning costs Asset retirement obligations Accrued pension and benefit obligations Power contract derivatives Other deferred credits - regulatory Other Total deferred credits and other liabilities Commitments and contingencies TOTAL CAPITALIZATION AND LIABILITIES			26,087 4,194 14,134 3,520 23,175 20,491 17,201 28,564 137,366 $559,049				32,379 4,478 17,183 3,643 23,508 5,735 11,155 29,416 127,497 $546,763
The accompanying notes are an integral part of these consolidated financial statements Page 6 of 65
CONDENSED CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (in thousands) (unaudited)
	Three Months Ended September 30 2005 2004			Nine Months Ended September 30 2005 2004
Retained earnings at beginning of period Net income from continuing operations Net income from discontinued operations Retained earnings before dividends	$89,343 2,721 - 92,064	$94,062 6,057 8 100,127		$100,512 184 - 100,696					$88,282 7,565 12,354 108,201
Cash dividend declared Preferred stock Common stock Total dividends declared Performance share plan Retained earnings at end of period	92 2,825 2,917 - $89,147	259 6 265 - $99,862		276 11,273 11,549 - $89,147					775 8,344 9,119 780 $99,862
The accompanying notes are an integral part of these consolidated financial statements Page 7 of 65 CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited) (in thousands)
					Nine Months Ended September 30 2005 2004
Cash flows provided (used) by: OPERATING ACTIVITIES Net income Deduct: Income 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 Equity in earnings from non-utility investments Distribution of earnings from non-utility investments Deferred revenue from non-utility investments Depreciation Amortization of capital leases Deferred income taxes and investment tax credits Net amortization of purchased power and related costs Regulatory amortizations Non-cash charge related to Rate Order Customer refunds related to Rate Order Reserve for loss on power contract (SFAS No. 5 loss accrual) Gain on sale of non-utility investments Non-utility asset impairment charges Losses and amortization of premiums on available-for-sale securities Changes in assets and liabilities: Decrease in accounts receivable and unbilled revenues Decrease in accounts receivable - affiliates Decrease in accounts payable Decrease in accounts payable - affiliates Decrease in accrued income taxes Decrease (increase) in other current assets Increase in special deposits Increase (decrease) in other current liabilities (Increase) decrease in other long-term assets Decrease in other long-term liabilities and other Net cash provided by operating activities of continuing operations					$184 - 184 (1,446) 1,471 (1,386) 4,076 1,393 12,254 758 (6,408) 818 (1,384) 21,843 (6,531) - (74) 266 873 4,667 573 (1,973) (831) (3,223) 703 (21,532) 2,640 (906) (810) 6,015			$19,919 12,354 7,565 (881) 863 (3,747) 6,934 - 12,045 823 (1,519) (2,485) 121 - - 14,351 (1,980) - - 3,316 2,171 (3,278) (1,181) (9,555) (262) - (97) 3,550 (4,568) 22,186
INVESTING ACTIVITIES Construction and plant expenditures Non-utility investments Investments in available-for-sale securities Proceeds from sale of available-for-sale securities Proceeds from repayment of non-utility notes Increase in restricted cash - non-utility Increase in restricted cash - utility Non-utility notes receivable Proceeds from sale of non-utility investments Return of capital from non-utility investments Return of capital from utility investments and other Net cash used for investing activities of continuing operations					(11,324) (16,953) (206,726) 219,916 28,040 (22,431) (507) (3,969) 12 2,480 610 (10,852)			(15,195) (16,926) (282,796) 270,101 - - (648) - 4,571 2,082 283 (38,528)
FINANCING ACTIVITIES Proceeds from exercise of stock options Proceeds from dividend reinvestment program Decrease in restricted cash Proceeds from issuance of long-term debt Retirement of preferred stock Retirement of long-term debt Common and preferred dividends paid Reduction in capital lease obligations Debt issuance costs and other Net cash provided by (used for) financing activities of continuing operations					252 911 2,000 14,374 (2,000) (534) (9,099) (758) (495) 4,651			498 1,458 2,000 75,000 (2,000) (77,660) (9,119) (823) (428) (11,074)
Effect of exchange rate changes on cash Cash flow provided by discontinued operations - investing activities Net (decrease) increase in cash and cash equivalents Cash and cash equivalents at beginning of the period Cash and cash equivalents at end of the period					- - (186) 11,722 $11,536			(18) 30,164 2,730 23,772 $26,502

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

Page 8 of 65

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - BUSINESS ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

About Central Vermont Public Service Corporation Central Vermont Public Service Corporation (the "Company") is a Vermont-based electric utility that transmits, distributes and sells electricity, and invests in renewable and independent power projects. The Company's wholly owned subsidiary, Catamount Resources Corporation ("CRC") holds subsidiaries that invest in unregulated businesses. These subsidiaries include: Catamount Energy Corporation ("Catamount"), which invests primarily in wind energy projects in the United States and the United Kingdom; Eversant Corporation ("Eversant"), which operates a rental water heater business through its subsidiary, SmartEnergy Water Heating Services, Inc.; Custom Investment Corporation, a passive investment subsidiary; and Connecticut Valley Electric Company, Inc. ("Connecticut Valley"), which distributed and sold electricity in parts of New Hampshire. On January 1, 2004, Connecticut Valley completed the sale of substantially all of its plant assets and franchise. See Note 10 - Discontinued Operations.

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

Regulatory Accounting The Company is regulated by the Vermont Public Service Board ("PSB"), the Connecticut Department of Public Utility and Control and the Federal Energy Regulatory Commission ("FERC"), with respect to rates charged for service, accounting, financing and other matters pertaining to regulated operations. The Company prepares its financial statements in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71, Accounting for the Effects of Certain Types of Regulation ("SFAS No. 71"), for its regulated Vermont service territory and FERC-regulated wholesale business. On March 29, 2005, the PSB issued its Order ("Rate Order") on the rate investigation and the Company's request for a rate increase, described in Note 8 - Retail Rates. Although, the Rate Order had a significant unfavorable effect on the Company's financial position and results of operations for the first nine months of 2005, the Company's regulated business continues to meet the criteria for accounting under SFAS No. 71. Based on a current evaluation of the factors and conditions expected to impact future cost recovery, management believes future recovery of its regulatory assets in the State of Vermont for its retail and wholesale businesses is probable.

In the event that the Company no longer meets the criteria under SFAS No. 71 and there is not a rate mechanism to recover these costs, the accounting impact would be an extraordinary charge to operations of about $34.0 million pre-tax as of September 30, 2005. See Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits for additional information.

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

	September 30, 2005	December 31, 2004
Deferred compensation plans Accrued employee costs - payroll and medical Other taxes and Energy Efficiency Utility Environmental and accident reserves Customer deposits, prepayments and interest Obligation under capital leases Reserve for loss on power contract Accrued joint-owned expenses Reserve for tariff settlement - pole attachments Miscellaneous accruals Total	$2,586 4,369 5,081 567 1,210 1,020 1,196 407 897 3,948 $21,281	$2,689 4,277 2,800 1,503 1,753 1,020 1,196 276 341 4,476 $20,331

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

	September 30, 2005	December 31, 2004
Environmental Reserve Non-legal asset retirement obligation Contribution in aid of construction - tax adder Reserve for loss on power contract Other Total	$5,072 7,426 4,760 11,062 244 $28,564	$5,045 6,743 4,530 11,959 1,139 $29,416

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

	Three Months Ended September 30, 2005 2004		Nine Months Ended September 30, 2005 2004
Non-utility revenue Interest on non-utility notes receivable Interest income - IRS audit refunds Interest on temporary investments Amortization of contributions in aid of construction Non-operating rental income Regulatory asset carrying costs Other interest and dividends Carrying costs - Rate Order* Miscellaneous other income Total	$174 47 - 299 210 213 - 412 - 119 $1,474	$166 61 - 355 208 183 201 50 - 13 $1,237	$1,627 740 - 1,005 628 591 169 603 (822) 189 $4,730	$1,468 101 970 1,029 620 600 622 158 - 118 $5,686
* Reflects first quarter 2005 Rate Order adjustments primarily related to amortization of Vermont Yankee sale costs and Vermont Yankee fuel rod costs for April 1, 2004 through March 31, 2005. See Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits.

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

	Three Months Ended September 30, 2005 2004		Nine Months Ended September 30, 2005 2004
Non-utility other operating expense Realized losses on available-for-sale securities Non-utility bad debt expense Vermont Yankee fuel rod disallowance - Rate Order* Supplemental retirement benefits and insurance Non-utility business development and consulting expense Other taxes Intangible asset amortization Asset impairment charges - Catamount Miscellaneous other deductions Non-utility expenses Total	$1,131 - (144) - 150 76 75 43 - 194 32 $1,557	$1,068 - 91 - 234 217 47 91 - 63 15 $1,826	$3,629 573 392 403 575 350 329 130 266 442 58 $7,147	$3,105 - 106 - 371 632 146 311 - 330 68 $5,069
* Reflects first quarter 2005 Rate Order disallowance of a portion of deferred costs related to a Vermont Yankee unscheduled outage in mid-2002. See Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits.

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Stock-Based Compensation The Company applies Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees ("APB 25"), and related Interpretations in accounting for its stock option plans and follows the disclosure requirements of SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of SFAS No. 123. The table below illustrates the effect on net income and earnings per share as if the fair value method had been applied to all outstanding and unvested awards in each period. The fair value of options at date of grant was estimated using the Black Scholes option-pricing model.

	Three Months Ended September 30, 2005 2004		Nine Months Ended September 30, 2005 2004
Earnings (loss) available for common stock, as reported Deduct: Total stock-based employee compensation* Pro forma net income Earnings (loss) per share: Basic - as reported Basic - pro forma Diluted - as reported Diluted - pro forma * Fair value based methods for all awards, net of related tax effects.	$2,629 - $2,629 $0.21 $0.21 $0.21 $0.21	$5,806 23 $5,783 $0.48 $0.48 $0.47 $0.47	$(92) 130 $(222) $(.01) $(.02) $(.01) $(.02)	$19,144 236 $18,908 $1.58 $1.56 $1.56 $1.54

Earnings Per Share ("EPS") The Condensed Consolidated Statements of Income includes 'basic' and 'diluted' per share information. Basic EPS is calculated by dividing net income, after preferred dividends, by the weighted-average common shares outstanding for the period. Diluted EPS follows a similar calculation except that the weighted-average common shares is increased by the number of potentially dilutive common shares. Also, unvested restricted stock is only included in the computation of diluted shares as they are contingent upon vesting. The table below provides a reconciliation of earnings available for common stock and average basic and diluted common shares (in thousands, except share information):

Three Months Ended
September 30,
   2005             2004

Nine Months Ended
September 30,
   2005             2004

Net income
Preferred stock dividend
Earnings (loss) available for common stock

$2,721
      92
$2,629

$6,065
     259
$5,806

$184
     276
$(92)

$19,919
       775
$19,144

Average shares of common stock outstanding - basic
   Dilutive effect of stock options
   Dilutive effect of restricted stock
   Dilutive effect of performance plan shares
Average share of common stock outstanding - diluted

12,276,642
83,729
4,892
                -
12,365,263

12,138,847
123,555
5,892
       28,445
12,296,739

12,251,944
-
-
                -
12,251,944

12,105,248
137,320
5,892
       28,445
12,276,905

The calculation of diluted EPS for the three months ended September 30, 2005 excludes 298,621 shares of common stock issuable upon exercise of stock options because their inclusion in the calculation would be anti-dilutive. Since the Company incurred a loss for the nine months ended September 30, 2005, common shares issuable upon exercise of stock options and unvested restricted stock are not included in the calculation of diluted EPS.

The calculation of diluted EPS for the three months ended September 30, 2004 excludes 27,500 shares of common stock issuable upon exercise of stock options because their inclusion in the calculation would be anti-dilutive. For the nine months ended September 30, 2004, all outstanding stock options were included in the computation of diluted shares because the exercise prices were lower than the average market price of the common shares in the period.

Derivative Financial Instruments
Power Contracts: The Company accounts for various power contracts as derivatives under the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted and SFAS No. 149, Amendment of Statement 133 Derivative Instruments and Hedging Activities, (collectively "SFAS No. 133"). These statements require that derivatives be recorded on the balance sheets at fair value. Adoption and application of these statements did not impact the Company's results of operations.

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The Company has a long-term purchased power contract that allows the seller to repurchase specified amounts of power with advance notice (Hydro-Quebec Sellback #3). This contract has been determined to be a derivative under SFAS No. 133. The derivative's estimated fair value was an unrealized loss of $5.3 million at September 30, 2005 and $5.7 million at December 31, 2004. 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.

The Company has a long-term forward sale contract for the sale of about 15 MW per hour, or a total of 522,544 beginning November 17, 2004 through December 31, 2008. This contract has been determined to be a derivative under SFAS No. 133. The Company utilizes over-the-counter quotations or broker quotes at the end of the reporting period for determining the fair value of this contract. The derivative's estimated fair value was an unrealized loss of $15.2 million at September 30, 2005 and a $0.4 million unrealized gain at December 31, 2004.

The Company records derivative contracts on the Consolidated Balance Sheets at fair value. Based on a PSB-approved Accounting Order, the Company records the change in fair value of these derivatives as deferred charges or deferred credits on the balance sheet, depending on whether the fair value is an unrealized loss or gain.

Catamount: On July 12, 2005, a wholly-owned subsidiary of Catamount entered into a fixed interest rate swap agreement to hedge the variable interest rate debt under the financing agreement described in Note 6 - Long-Term Debt and Sinking Fund Requirements. The swap is for 75 percent of the borrowing amount, or $10.8 million, with a 4.5 percent fixed rate. Other terms of the swap such as variable interest rate pricing, quarterly interest rate reset, quarterly interest payment schedule and December 31, 2013 maturity date are the same as those under the financing agreement. The swap agreement has not been designated as a hedging instrument and the changes in the fair value will be recorded on the Consolidated Statement of Income. The fair value is less than $0.1 million at September 30, 2005.

Assets Held for Sale In the second quarter of 2005, the Company completed the sale of its property located in Ascutney, Vermont. The sale included the land and service center building which was no longer being used by the Company. The net book value of the property was about $0.4 million when it was sold. The sale resulted in a gain of a nominal amount which is offset in accumulated depreciation based on regulatory accounting treatment that requires that sale costs and any related loss or gain on the sale of utility-owned property be offset in accumulated depreciation. The Company had classified this asset as held for sale on its first quarter 2005 Condensed Consolidated Balance Sheet in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.

Investments in Marketable Securities The Company accounts for investments in marketable equity and debt securities in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities ("SFAS No. 115"). At September 30, 2005, all of the Company's marketable securities, except money market funds included in cash and cash equivalents, were classified as available-for-sale and reported at fair value. Unrealized gains and losses are reported as a component of accumulated other comprehensive income, net of tax, in common stock equity. The carrying cost of debt securities is adjusted for amortization of premiums and accretion of discounts from the date of purchase to maturity.

The Company evaluates the carrying value of its investments on a quarterly basis, or when events and circumstances warrant, determining whether a decline in fair value should be considered other-than-temporary. The carrying value is considered impaired when the anticipated fair value, based on cash flow forecasts, is less than the carrying value of each investment. In that event, a realized loss is recognized based on the amount by which the carrying value exceeds the fair value of the investment. The Company uses the amortized cost basis in computing realized gains and losses on the sale of its available-for-sale securities. These realized gains and losses are included in other income or deductions. See Note 5 - Investment Securities.

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

Restricted Cash At September 30, 2005, Restricted cash included $22.4 million, primarily related to Catamount's funding commitments for the Sweetwater 3 wind project and $0.5 million related to property release requirements under the Company's first mortgage indenture. Restricted cash at December 31, 2004 was related to mandatory redeemable preferred stock, including $1.0 million for the mandatory sinking fund payment and $1.0 million for the optional sinking fund payment. These payments to the Preferred Shareholders were effective on January 1, 2005.

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Special Deposits At September 30, 2005, Special deposits included $21.5 million of collateral payments made under performance assurance requirements for certain of the Company's power contracts. See Note 9 - Commitments and Contingencies - Performance Assurance.

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

Nine Months Ended
September 30,
2005                     2004

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

$5,370
$6,431

$7,956
$14,531

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

Non-cash Operating, Investing and Financing Activities For additional information regarding non-cash activities, see Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits, Note 8 - Retail Rates and Note 9 - Commitments and Contingencies.

Reclassifications The Company will record reclassifications to prior year financial statements when considered necessary or to conform to current-year presentation. The reclassification of auction rate securities from cash and cash equivalents to short-term available-for-sale securities in the December 31, 2004 balance sheet resulted in a decrease of $11.5 million to the ending cash and cash equivalents line items as previously presented in the Condensed Consolidated Statement of Cash Flows for the nine months ended September 30, 2004. The reclassifications also impacted cash flows used in investing activities and net increase in cash and cash equivalents of $22.9 million for the nine months ended September 30, 2004. There was no impact on net income, cash flow from operations, total assets or covenants as a result of this reclassification.

Non-utility return of capital of $2.1 million provided by investing activities was reclassified from distribution of earnings from non-utility investments provided by operating activities for the nine months ended September 30, 2004 in the Condensed Consolidated Statement of Cash Flows. There was no impact on the net change in cash and cash equivalents.

Recent Accounting Pronouncements
SFAS No. 123R: In December 2004, the Financial Accounting Standards Board ("FASB") issued SFAS No. 123R, Share-Based Payments ("SFAS No. 123R"), which replaces SFAS No. 123 and supersedes APB 25. SFAS No. 123R requires that compensation cost relating to share-based payment transactions be recognized in the financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. SFAS No. 123R will be effective for the Company in the first quarter of 2006 and will apply to all of the Company's outstanding unvested share-based payment awards as of January 1, 2006 and all prospective awards.

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

FIN 47: In March 2005, FASB issued FIN 47, Accounting for Conditional Asset Retirement Obligations ("FIN 47"), which clarifies that the term 'conditional asset retirement obligation' as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The interpretation further clarified that uncertainty surrounding the timing and method of settlement of the obligation should be factored into the measurement of the conditional asset retirement obligation rather than affect whether a liability should be recognized. FIN 47 is effective for the Company in the fourth quarter of 2005. The Company has not completed the process of evaluating the impact, if any, FIN 47 will have on its financial position or results of operations and cash flows.

Page 13 of 65

Accounting for Uncertain Tax Positions: Since July 2004, FASB has been discussing potential changes or clarifications in the criteria for recognition of tax benefits that may result in raising the threshold for recognizing tax benefits, which have some degree of uncertainty. On July 14, 2005, the FASB issued an Exposure Draft on accounting for uncertain tax positions under SFAS No. 109, Accounting for Income Taxes. The FASB expects to issue a final Interpretation in the first quarter of 2006. If adopted as proposed, only tax benefits that meet the probable recognition threshold may be recognized or continue to be recognized on the effective date. Initial derecognition amounts will be reported as a cumulative effect of a change in accounting principal. The Company has not yet evaluated the impact the proposed interpretation would have on other existing income tax positions.

SFAS No. 154: In May 2005, FASB issued SFAS No. 154, Accounting Changes and Error Corrections, ("SFAS No. 154"), which replaces Accounting Principals Board Opinion No. 20, Accounting Changes and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. SFAS No. 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to do so. SFAS No. 154 also provides that (1) a change in the method of depreciating or amortizing a long-lived nonfinancial asset be accounted for as a change in estimate (prospectively) that was effected by a change in accounting principle, and (2) correction of errors in previously issued financial statements should be termed a "restatement." The new standard is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. Early adoption of this standard is permitted for accounting changes and corrections of errors made in fiscal years beginning after June 1, 2005.

NOTE 2 - INVESTMENTS IN AFFILIATES
Vermont Electric Power Company, Inc ("VELCO") Summarized financial information follows (in thousands):

Three Months Ended
September 30,
   2005                2004

Nine Months Ended
September 30,
   2005                2004

Operating revenues
Operating income
Net income

Company's ownership interest:
   Common stock *

    Preferred stock

Company's equity in net income

$7,248
$2,088
$739

47.02%
48.03%

$363

$6,363
$2,121
$779

50.49%
46.62%

$308

$22,754
$6,228
$2,212

47.02%
48.03%

$1,075

$19,239
$5,322
$1,397

50.49%
46.62%

$583

* The decrease in ownership percentage reflects acquisitions of voting common stock issued by VELCO in    amounts below the Company's pro-rata ownership interest at the time.

VELCO and its wholly owned subsidiary, Vermont Electric Transmission Company, Inc., own and operate an integrated transmission system in Vermont over which bulk power is delivered to all electric utilities in the State. VELCO bills the Company on a monthly basis for transmission and administrative costs associated with power and transmission services; including various credits such as those from ISO-New England under the NEPOOL Open Access Transmission Tariff. These costs are included in Production and Transmission on the Condensed Consolidated Statements of Income and amounted to a credit of $0.2 million in the third quarter and a charge of $1.4 million in the first nine months of 2005, compared to charges of $0.3 million in the third quarter and $5.5 million in the first nine months of 2004. Accounts payable to VELCO amounted to $4.8 million at September 30, 2005 and $4.8 million at December 31, 2004.

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

Three Months Ended
September 30,
2005 2004

Nine Months Ended
September 30,
2005 2004

Operating revenues
Operating income (loss)
Net income

Company's ownership interest: 58.85%

Company's equity in net income

$41,918
$543
$169

$100

$44,131
$85
$130

$76

$125,227
$(804)
$511

$301

$118,328
$(83)
$401

$236

Page 14 of 65

The Company has a 35 percent entitlement in Vermont Yankee plant output sold by Entergy Nuclear Vermont Yankee, LLC ("ENVY") to VYNPC, through a long-term power purchase contract ("PPA") with VYNPC. The Company's purchases from VYNPC are shown in the table below. Accounts payable to VYNPC amounted to $5.0 million at September 30, 2005 and $5.8 million at December 31, 2004. Also See Note 9 - Commitments and Contingencies for additional information related to VYNPC.

Other Affiliates The Company has equity ownership interests in three nuclear plants, including 2 percent in Maine Yankee Atomic Power Company ("Maine Yankee"), 2 percent in Connecticut Yankee Atomic Power Company ("Connecticut Yankee"), and 3.5 percent in Yankee Atomic Electric Company ("Yankee Atomic"). These plants are permanently shut down and are conducting decommissioning activities. The Company's shares of decommissioning and other related costs for each plant are included in purchased power expense as shown in the table below. Accounts payable for all three plants amounted to $0.1 million at September 30, 2005 and $0.2 million at December 31, 2004. The Company's obligations related to these plants are described in Note 9 - Commitments and Contingencies.

Purchased Power - Affiliates
The Company's purchases from VYNPC, and costs related to Maine Yankee, Connecticut Yankee and Yankee Atomic decommissioning are included in Purchased Power - affiliates on the Condensed Consolidated Statements of Income. These purchases are summarized in the table below (in thousands):

	Three Months Ended September 30, 2005 2004		Nine Months Ended September 30, 2005 2004
Vermont Yankee Maine Yankee Connecticut Yankee Yankee Atomic Total Purchased Power - affiliates	$14,348 299 599 474 $15,720	$15,370 301 214 478 $16,363	$43,362 886 1,703 1,429 $47,380	$41,210 918 655 1,443 $44,226

NOTE 3 - NON-UTILITY INVESTMENTS
Catamount: Catamount invests in unregulated energy generation projects primarily in the United States and United Kingdom. As of September 30, 2005, Catamount had interests in six operating independent power projects located in Rumford, Maine; East Ryegate, Vermont; Nolan County, Texas; Thuringen, Germany and Mecklenburg-Vorpommern, Germany.

As of September 30, 2005, Catamount had Notes Receivable of $4.5 million, including a $3.9 million note associated with the construction of Sweetwater 3 and a $0.6 million note associated with the development of wind sites located in Nolan County, Texas. Also, at September 30, 2005, Catamount had restricted cash of $22.4 million, including $21.0 million related to Sweetwater 3, $1.2 million related to Catamount Sweetwater Holdings and $0.2 million related to collateralizing a letter of credit for a Catamount project.

Catamount recorded a loss of $0.2 million for the third quarter of 2005, compared to earnings of $1.4 million for the third quarter of 2004. Catamount recorded a loss of $0.7 million for the nine months ended September 30, 2005, compared to earnings of $2.0 million for the same period in 2004.

Catamount or its wholly owned subsidiaries provide certain management, accounting and other services to certain entities in which Catamount holds an equity interest. The fees are designed to recover actual costs or are agreed upon by other equity investors in these entities. Catamount's revenues (included in Other Income on the Condensed Consolidated Statements of Income) include billings of $0.1 million for the third quarters of 2005 and 2004, and $0.4 million and $0.5 million for the nine months ended September 30, 2005 and 2004, respectively. Accounts Receivable for these billings amounted to $0.7 million at September 30, 2005, of which $0.6 million was reserved, and amounted to $0.6 million at December 31, 2004, of which $0.5 million was reserved at December 31, 2004.

Information regarding certain of Catamount's investments follows:

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

Page 15 of 65

Sweetwater 3: The construction financing on Sweetwater 3, a 135-MW wind farm in Nolan County, Texas, closed on May 9, 2005 and as a result Catamount posted $24.8 million of security, representing Catamount's expected equity contribution, to be maintained in pledged collateral accounts for the construction lender. One of the accounts was funded with $16.4 million and will be drawn upon when all conditions precedent to the Sweetwater 3 equity close are achieved. Once this occurs, the funds will be Sweetwater 3 equity. The second account was funded with $8.4 million and will be drawn upon to pay construction costs. As the funds are drawn from this account, a note receivable with Sweetwater 3 will be created. The $24.8 million of security is included in Restricted Cash ($21 million, of which $0.1 million represents interest income) and Notes Receivable ($3.9 million) on the Condensed Consolidated Balance Sheet.

Rumford Cogeneration ("Rumford"): For the first and second quarters of 2005, Catamount determined that its equity investment in Rumford was impaired. Catamount prepared several scenarios based on varying electric energy prices and other assumptions which resulted in a range of possible outcomes ranging from no impairment to an impairment of $1.7 million. Management determined that the first and second quarter impairment was temporary based on the fact that the electric energy rate was being negotiated between the affected parties. In the third quarter of 2005, Management determined that its investment was no longer impaired based on updated analysis of a proposed energy contract between Rumford and the electric energy purchaser.

DK Burgerwindpark Eckolstadt and DK Windpark Kavelstorf GmbH&Co. KG (collectively "Eurowind":) In the first quarter of 2005, Catamount recorded an impairment of less than $0.1 million related to its Eurowind investments. Catamount recorded an additional impairment of $0.2 million in the second quarter of 2005. The impairment reflects Management's best estimate of the current market value of these investments based on a non-binding offer from a third party to purchase the projects.

Catamount Development GmbH Sale: In September 2005 Catamount sold its German development company, Development GmbH, to a third party for about $12,000. In the third quarter of 2005, Catamount recorded a gain on the sale of less than $0.1 million and net income tax benefits of $0.4 million.

Eversant: As of September 30, 2005, Eversant had a $1.4 million equity investment in The Home Service Store Inc. ("HSS"). HSS has established a network of affiliate contractors who perform home maintenance repair and improvements for its members. Eversant accounts for this investment on the cost basis.

NOTE 4 - REGULATORY ASSETS, DEFERRED CHARGES AND DEFERRED CREDITS
Under SFAS No. 71, the Company accounts for certain transactions in accordance with permitted regulatory treatment such that regulators may permit incurred costs, typically treated as expenses by unregulated entities, to be deferred and expensed in future periods when recovered in future revenues. In the Rate Order, the PSB determined the annual revenue requirement for the period April 1, 2004 through March 31, 2005, and established that rates during that period included recovery of certain deferred charges and regulatory liabilities. As a result, in the first quarter of 2005, the Company adjusted certain deferred charges and credits, and recorded amortizations of certain regulatory assets and regulatory liabilities as if they had begun on April 1, 2004. Additionally, certain deferred charges were reclassified to regulatory assets to reflect rate recovery. These Rate Order-related adjustments resulted in a $15.3 million decrease in net regulatory assets in the first quarter of 2005 with an offsetting $15.3 million pre-tax charge to earnings. See Note 8 - Retail Rates for additional information.

In addition to first quarter 2005 Rate Order charge, regulatory assets and certain other deferred credits are being amortized in accordance with the Rate Order. 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. The bulleted items a) - n) following the table provide information regarding certain of these regulatory items.

	(in thousands)
	September 30, 2005	December 31, 2004
Regulatory assets* Conservation and load management ("C&LM") (a) Nuclear refueling outage costs - Millstone Income taxes Maine Yankee nuclear power plant dismantling costs (b) Connecticut Yankee nuclear power plant dismantling costs (b) Yankee Atomic nuclear power plant dismantling costs (b) Vermont Yankee sale costs (non-tax) (c) Vermont Yankee fuel rod maintenance deferral (d) Other regulatory assets Subtotal Regulatory assets	$38 123 3,707 4,957 10,896 3,524 2,977 1,385 74 27,681	$408 647 3,987 5,843 2,108 - - - 148 13,141
Page 16 of 65
Other deferred charges - regulatory Vermont Yankee sale costs (tax) Vermont Yankee sale costs (non-tax) (c) Vermont Yankee replacement energy deferral (e) Connecticut Yankee incremental dismantling costs (b) Yankee Atomic incremental dismantling costs (b) Vermont Yankee fuel rod maintenance deferral (d) Pole treating expense (m) Unrealized loss on power contract derivatives (f) Subtotal Other deferred charges - regulatory	2,887 - - - - - 158 20,491 23,536	2,887 6,381 834 10,545 7,162 3,401 - 5,735 36,945
Other deferred credits - regulatory Millstone Unit #3 decommissioning (g) IPP settlement reimbursement and VEPPI cost mitigation (h) Vermont utility overearnings 2001 - 2003 (i) Connecticut Valley gain on termination of power contract (j) Vermont Yankee insurance refunds (k) Asset retirement obligation - Millstone Unit #3 Unrealized gain on power contract derivatives (f) Vermont Yankee IRS settlement (l) Tree trimming expense (m) Emission allowances and renewable energy credits (n) Other Subtotal Other deferred credits - regulatory	191 440 9,607 3,325 80 1,281 - 1,088 361 439 389 17,201	629 1,200 7,345 - - 1,078 385 - - 518 11,155
Net regulatory assets, deferred charges and deferred credits	$34,016	$38,931
* Regulatory assets are being recovered in retail rates and, with the exception of C&LM and Other regulatory assets, include an associated return.

Pursuant to the Rate Order, certain regulatory assets related to C&LM programs were reduced resulting in a $0.3 million pre-tax charge to earnings in the first quarter of 2005. Other costs are being amortized over a two-year period beginning April 1, 2004.
Estimated decommissioning costs related to the Company's equity investments in Maine Yankee, Connecticut Yankee and Yankee Atomic. See Note 9 - Commitments and Contingencies for additional information related to nuclear plant decommissioning. These costs are being recovered in retail rates. The Rate Order required the following: 1) previously deferred incremental dismantling costs for the 12 months ended March 31, 2005 be expensed to reflect rate recovery during that time; 2) Yankee Atomic incremental dismantling costs already paid by the Company be amortized over a three-year period ($0.5 million annually) beginning April 1, 2004, and 3) beginning April 1, 2006, for each plant, differences between actual decommissioning cost payments and amounts included for rate recovery, be deferred until the Company's next rate proceeding.

In the first quarter of 2005, the Company recorded a $2.4 million pre-tax charge to earnings to reflect Rate Order-required adjustments to incremental dismantling costs related to Connecticut Yankee ($0.2 million) and Yankee Atomic ($2.2 million). This included a $1.9 million charge to purchased power expense and a $0.5 million charge to operating expense. Deferred charges were also reclassified to regulatory assets, to reflect rate recovery. In addition to first quarter 2005 Rate Order-required adjustments, regulatory assets associated with these nuclear plants decreased about $3.9 million including $3.6 million related to payments for the Company's share of decommissioning costs in 2005 and $0.3 million related to Rate Order-required amortizations beginning April 1, 2005.
Regulatory asset related to deferred incremental Vermont Yankee sale costs (excluding incremental income tax expense) that resulted from the difference between costs that the Company would have incurred had it not pursued the sale and those it incurred by pursuing the sale. Pursuant to the Rate Order, these costs are being amortized over a three-year period ($2.0 million annually) beginning April 1, 2004.

In the first quarter of 2005, the Company recorded a $2.5 million pre-tax charge to earnings to reflect adjustments required in the Rate Order. This included a $2.0 million charge to operating expense and a $0.5 million reduction of interest income related to adjusted carrying costs. Deferred charges were also reclassified to regulatory assets, to reflect rate recovery. Rate Order-required amortizations beginning April 1, 2005 and carrying cost adjustments recorded in the first quarter of 2005 further reduced this regulatory asset by $0.9 million.

Page 17 of 65

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

In the first quarter of 2005, the Company recorded a $1.6 million pre-tax charge to earnings to reflect adjustments required in the Rate Order. This included a $0.9 million charge to operating expense, a $0.4 million charge to other deductions, and a $0.3 million decrease in interest income. Deferred charges were also reclassified to regulatory assets, to reflect rate recovery. Rate Order-required amortizations beginning April 1, 2005 and carrying cost adjustments recorded in the first quarter of 2005 further reduced this regulatory asset by about $0.4 million.

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

Required adjustments to the regulatory liability included: 1) a $12.1 million increase resulting from recalculation of overearnings for the periods 2001 - 2003; 2) a $3.8 million decrease resulting from amortization for April 1, 2004 through March 31, 2005; 3) a $0.3 million decrease related to adjusted carrying costs; and 4) a $3.8 million decrease resulting from reversal of the regulatory liability associated with 2004 utility overearnings. See Note 8 - Retail Rates for additional information. Rate Order-required amortizations beginning April 1, 2005 further reduced this regulatory liability by about $1.9 million.
Pursuant to the Rate Order, the Company was required to apply the 2004 pre-tax gain, resulting from termination of the power contract with Connecticut Valley, to the benefit of ratepayers through amortizations over a three-year period ($2.2 million annually) beginning April 1, 2004. In the first quarter of 2005, the Company established a regulatory liability in the amount of $6.6 million pre-tax, per the Rate Order, offset by amortization of $2.2 million. This resulted in a net $4.4 million pre-tax charge to earnings in the first quarter of 2005. See Note 8 - Retail Rates for additional information. Rate Order-required amortizations beginning April 1, 2005 further reduced this regulatory liability by about $1.1 million.

Page 18 of 65

Pursuant to PSB approval of the Vermont Yankee sale, distributions from Nuclear Electric Insurance Limited ("NEIL") and similar insurance providers received by Vermont Yankee and passed to the Company must benefit ratepayers through programs to promote renewable resources. On July 28, 2005, the PSB approved the Company's plan for use of these funds, which included 30 percent to the Vermont Small Wind and Solar Fund and 70 percent to the Renewable Development Trust Fund and the related voluntary renewable pricing program referred to as CVPS Cow Power. The remaining $0.1 million at September 30, 2005 includes the Company's share of a refund received in the third quarter of 2005 and a nominal amount related to CVPS Cow Power.
The Company received a $1.1 million credit or reduction in its June 2005 purchased power billing from VYNPC, representing its share of the settlement of a tax dispute payment received by VYNPC from the IRS. The Company recorded the credit (less a small portion related to wholesale) as a regulatory liability rather than a reduction in purchased power expense. The Company does not believe that IRS settlement constitutes 'excess funds' within the meaning of the PSB's June 2002 Order approving the Vermont Yankee sale, and its April 2004 Order approving use of NEIL funds received in 2003 and 2004. In August 2005, the PSB issued a memo accepting the Company's argument, but in its memo the PSB stated that it expects that the tax credit be treated in a manner that will inure to the benefit of ratepayers. The Company is currently evaluating alternatives for use of these funds.
The Rate Order required other adjustments mostly related to tree trimming and pole treating expenses that resulted in a $0.1 million pre-tax charge to earnings. Pursuant to the Rate Order, tree trimming and pole treating expenditures below those amounts included in retail rates are being deferred as regulatory liabilities and any amounts in excess are recorded as deferred charges. These amounts would then carry forward for use in future years.
Regulatory liabilities related to the Company's share of revenues from the sale of excess SO2 (sulfur dioxide) emission allowances (about $0.3 million) and the sale of renewable energy credits (about $0.05 million). The emission allowances were related to the Company's joint-owned units, Wyman Unit 4 and McNeil Generating Station. The renewable energy credits were related to credits created from Company-owned facilities. Based on regulatory accounting requirements these revenues are recorded as regulatory liabilities. In July 2005, the Company submitted a draft Accounting Order to the PSB for approval to defer revenue from the sale of emission allowances and renewable energy credits. In September 2005, the DPS recommended that the PSB not grant the Accounting Order due to materiality and recommended guidance for when accounting orders should be granted. That guidance, which would apply to all Vermont utilities, is still being discussed, but the outcome is not expected to affect the Company's current accounting for emission allowances and renewal energy credits.

NOTE 5 - INVESTMENT SECURITIES
Available-for-sale securities At September 30, 2005, Current Assets associated with available-for-sale securities decreased by $0.7 million and available-for-sale securities included in Investments and Other Assets decreased by $13.0 million, reflecting the scheduled maturity of certain available-for-sale securities and the expected maturity of other available-for-sale securities within one year.

The Company evaluates the carrying value of these investments on a quarterly basis, or when events and circumstances warrant, to determine whether a decline in fair value is considered temporary or other-than-temporary. The Company considers several criteria in evaluating other-than-temporary declines, including 1) length of time and extent to which market value has been less than cost; 2) financial condition and near-term prospects of the issuer; and 3) intent and ability of the Company to retain its investment in the issuer for a period of time sufficient to allow for any anticipated recovery in market value. In the first quarter of 2005, the Company recorded a $0.3 million impairment of certain available-for-sale investments based on its intent to liquidate those securities prior to their original maturity dates. Based upon forecasted cash flow needs at that time, those securities closest to maturity were impaired. Generally, a security close to its maturity date should have less pricing volatility due to interest rate movements than one further from its maturity date. In the second and third quarters of 2005, the Company determined that there was no further impairment related to these investment securities.

In the first quarter of 2005, the Company recorded $0.1 million of realized losses and $0.3 million of debt security premium amortizations to interest income as a deduction from the coupon interest earned on available-for-sale securities. The Company recorded minimal losses in the second quarter and minimal gains in the third quarter of 2005. Premium amortizations of $0.4 million were recorded in the nine months of 2005.

Page 19 of 65

The unrealized losses on available-for-sale securities shown below, both on an individual and aggregate basis, are minor when compared to the original costs, and are related to securities the Company expects to hold to maturity based on forecasted cash needs. Therefore, such unrealized losses are considered temporary. Information regarding available-for-sale securities as of September 30, 2005 follows (in thousands):

	September 30, 2005				December 31, 2004
Security Types	Amortized Cost	Fair Value	Unrealized Gains	Unrealized Losses	Amortized Cost	Fair Value	Unrealized Gains	Unrealized Losses
Current Assets: US Government Obligations US Government Agencies Corporate Bonds Auction Rate Securities Subtotal Investments and Other Assets: US Government Obligations US Government Agencies Corporate Bonds Subtotal Total	$ - 10,373 5,089 3,125 18,587 - 7,444 1,512 8,956 $27,543	$ - 10,395 5,080 3,125 18,600 - 7,404 1,516 8,920 $27,520	$ - 56 18 - 74 - - 4 4 $78	$ - 34 27 - 61 - 40 - 40 $101	$2,006 8,060 4,442 4,825 19,333 - 15,492 6,657 22,149 $41,482	$2,002 8,010 4,425 4,825 19,262 - 15,336 6,582 21,918 $41,180	- - - - - - - - - -	$4 50 17 - 71 - 156 75 231 $302

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, 2005 (in thousands):

	Equity Securities		Debt Securities
	Fair Value	Unrealized Losses	Fair Value	Unrealized Losses
Less than 12 months 12 months or more Total	- - -	- - -	$7,404 4,976 $12,380	$40 61 $101

Information related to the fair value of debt securities at September 30, 2005 follows (in thousands):

Fair value of debt securities at contractual maturity dates

Debt Securities

Less than 1 year
$15,476

1 to 5 years
$8,920

5 to 10 years
-

After 10 years
-

Total
$24,396

Millstone Decommissioning Trust Fund The Company has decommissioning trust fund investments related to its joint-ownership interest in Millstone Unit #3. The decommissioning trust fund was established pursuant to various federal and state guidelines. Among other requirements, the fund is required to be managed by an independent and prudent fund manager. Any gains or losses, realized and unrealized, are expected to be refunded to or collected from ratepayers, respectively. For that reason, the fair value is adjusted by realized and unrealized gains and losses, with a corresponding decommissioning liability recorded as Asset Retirement Obligations on the Condensed Consolidated Balance Sheets.

These investments are subject to the requirements of SFAS No. 115, and are recorded at fair value in Investments and Other Assets on the Condensed Consolidated Balance Sheets. The unrealized losses on the decommissioning trust fund are minor when compared to their original cost; therefore, they are considered temporary. The fair value of these investments is summarized below (in thousands):

	September 30, 2005				December 31, 2004
Security Types	Amortized Cost	Fair Value	Unrealized Gains	Unrealized Losses	Amortized Cost	Fair Value	Unrealized Gains	Unrealized Losses
Equity Securities Debt Securities Cash and other Total	$2,400 1,116 198 $3,714	$3,455 1,148 198 $4,801	$1,074 36 - $1,110	$19 4 - $23	$2,464 1,103 40 $3,607	$3,537 1,144 40 $4,721	$1,093 43 - $1,136	$20 2 - $22

Page 20 of 65

The following table presents the gross unrealized losses and fair value of certain investments, aggregated by investment category and the length of time the securities have been in a continuous loss position, at September 30, 2005 (in thousands):

	Equity Securities		Debt Securities
	Fair Value	Unrealized Losses	Fair Value	Unrealized Losses
Less than 12 months 12 months or more Total	$202 - $202	$19 - $19	$5 339 $344	$ - 4 $4

Information related to the fair value of debt securities at September 30, 2005 follows (in thousands):

Fair value of debt securities at contractual maturity dates

Debt Securities

Less than 1 year
$15

1 to 5 years
$330

5 to 10 years
$270

After 10 years
$533

Total
$1,148

NOTE 6 - LONG-TERM DEBT AND SINKING FUND REQUIREMENTS
Utility The Company has 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 expire on November 30, 2005. On September 30, 2005, the Company received PSB approval to extend these letters of credit for another year. Also on September 30, 2005, these letters of credit were extended by the bank to November 30, 2006. Because of the Company's non-investment grade credit rating, the bank required that these letters of credit now be secured under the Company's first mortgage indenture. At September 30, 2005, there were no amounts outstanding under these letters of credit.

Non-utility On July 12, 2005, Catamount Sweetwater Holdings, LLC (the "Borrower"), a wholly owned subsidiary of Catamount, entered into a senior secured Financing Agreement (the "Facility") for up to about $31.0 million of loan commitments with two lenders. The total loan commitment is comprised of a $14.4 million Tranche A amount based on the Borrower's wholly owned subsidiaries' equity interests in the Sweetwater 1 and 2 operating wind projects and a $16.5 million Tranche B amount based on the Borrower's wholly owned subsidiaries' equity interests anticipated in Sweetwater 3, currently under construction and scheduled to be operating in late December 2005 or early January 2006. The actual Tranche B amount will be based on the final economics for Sweetwater 3 when it is placed in commercial operation.

The maturity date for each Tranche is based on the date cash distributions are made under the Facility. The Sweetwater 1 and 2 maturity dates are anticipated to be no later than December 2013 and December 2012, respectively, for an expected average outstanding borrowing of 8.5 years from the borrowing date. The Sweetwater 3 maturity date is anticipated to be no later than December 2012, for an expected outstanding borrowing of seven years from the borrowing date. The Tranche A and B borrowings are priced at a variable interest rate based on the three month LIBOR (London Interbank Overnight Rates).

The Tranche A borrowing occurred upon close of the Facility and Tranche B borrowing will be available through December 2006, which is about one year from the anticipated commercial operation date of Sweetwater 3. All cash distributions from the respective projects received by each of the Borrower's wholly owned subsidiaries will be applied to the outstanding loans based on the maximum permitted loan balance at each scheduled repayment date for each Tranche. If the cash distributions are greater than the amount due at each scheduled repayment date, then the amount in excess of the amount due will be held in a fixed reserve account to be used at future scheduled repayment dates or until such time as the Facility is paid in full.

The Facility is secured by a first-priority lien on all of the Borrower's wholly owned subsidiaries' membership interests in the Sweetwater 1 and 2 wind projects. If the Tranche B borrowings are activated, then Sweetwater 3 will be subject to a first-priority lien under the Facility. The Facility has limited recourse to Catamount, but only in the event of the loss of certain production tax credits, loss of cash distributions and other matters as defined in the Facility. The Facility is non-recourse to the Company.

When the facility closed on July 12, 2005, the Borrower entered into a fixed interest rate swap agreement with the lenders to mitigate interest variability risk. The swap is for 75 percent of the borrowing amount, or $10.8 million, with a 4.5 percent fixed rate. Other terms of the swap such as variable interest rate pricing, quarterly interest rate reset, quarterly interest payment schedule and December 31, 2013 maturity date are the same as those under the Facility. See Note 1 - Business Organization and Summary of Significant Accounting Policies.

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On July 12, 2005, Catamount borrowed $14.4 million under the Facility and used the proceeds to pay off the $12.8 million bridge loan that the Company extended in April 2005. The remaining amount was used to fund the required debt service reserve account and pay certain transaction costs.

NOTE 7 - PENSION AND POSTRETIREMENT BENEFITS
Benefit Plan Trust Assets: At September 30, 2005, the fair value of Pension Plan trust assets was $67.8 million. At December 31, 2004, the fair value of Pension Plan trust assets was $64.2 million. At September 30, 2005, the fair value of Postretirement Plan trust assets was $6.2 million. At December 31, 2004, the fair value of Postretirement Plan trust assets was $5.0 million.

Benefit Plan Trust Contributions: In September 2005, the Company funded the minimum required contribution of about $3.4 million to the defined Pension Plan trust and contributed about $1.1 million to the Postretirement Plan 401(h) trust. In addition, the Company funded about $1.4 million of out-of-pocket Postretirement Plan benefits in the first nine months of 2005.

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

Pension Benefits	Three Months Ended September 30, 2005 2004		Nine Months Ended September 30, 2005 2004
Net benefit costs include the following components Service cost Interest cost Expected return on plan assets Amortization of prior service cost Recognized net actuarial loss Amortization of transition asset Net periodic benefit cost Less amounts capitalized Net benefit costs expensed	$807 1,464 (1,317) 100 49 - 1,103 171 $932	$755 1,388 (1,406) 99 - (37) 799 139 $660	$2,421 4,392 (3,951) 300 147 - 3,309 514 $2,795	$2,265 4,164 (4,218) 297 - (111) 2,397 390 $2,007

Postretirement Benefits	Three Months Ended September 30, 2005 2004		Nine Months Ended September 30, 2005 2004
Net benefit costs include the following components Service cost Interest cost Expected return on plan assets Amortization of prior service cost Recognized net actuarial loss Amortization of transition obligation Net periodic benefit cost Less amounts capitalized Net benefit costs expensed	$128 361 (119) - 278 64 712 110 $602	$135 389 (108) - 345 64 825 144 $681	$384 1,083 (357) - 834 192 2,136 332 $1,804	$405 1,167 (324) - 1,035 192 2,475 403 $2,072

The estimated Medicare Part D subsidy for retirees over age 65 who are offered benefits, included in net periodic benefit cost above is about $0.2 million for the nine months of 2005 and is expected to be about $0.3 million for the year. The Company has filed an application with the Center for Medicare and Medicaid Services for the Medicare Part D subsidy.

NOTE 8 - RETAIL RATES
The Company recognizes adequate and timely rate relief is required to maintain its financial strength, particularly since Vermont law does not allow purchased power and fuel costs to be passed on to consumers through purchased power and fuel adjustment clauses. The Company will continue to review costs and request rate increases when warranted.

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

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

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

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

On March 29, 2005, the PSB issued its Order ("Rate Order") on the rate investigation and the Company's request for a rate increase. The PSB concluded that the Company's rates were higher than is just and reasonable, and must be reduced. In the Rate Order, the PSB determined the annual revenue requirement for the period beginning April 1, 2004, established rates retroactive to April 7, 2004 and established new rates beginning April 1, 2005. The Rate Order included, among other things, the following: 1) a 1.88 percent rate reduction beginning April 1, 2005; 2) a $3.3 million 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 Company was also required to file a compliance filing by April 1, 2005, which it did, and file a new rate design within 90 days of the Rate Order. The PSB subsequently approved the Company's request for an extension on the rate design filing.

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

For accounting purposes, the Rate Order resulted in a $21.8 million pre-tax unfavorable effect on utility earnings for 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 over-collections for the period April 7, 2004 through March 31, 2005; and 4) amortization of costs and other adjustments required in the Rate Order. These are described in more detail below (all on a pre-tax basis).

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

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

In the first quarter of 2005, the Company recorded a $10.8 million charge to operating expense and $1.3 million to other interest expense, offset by a $12.1 million regulatory liability, to reflect the amount to be amortized. The Company also recorded amortizations for the 12 months ending March 31, 2005, which reduced operating expense and the regulatory liability by $3.8 million. In total, this amounted to a net $8.3 million charge to earnings.

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

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

In the first quarter of 2005, the Company recorded a $6.6 million charge to operating expense, offset by a regulatory liability, to reflect the amount to be amortized. The Company also recorded amortizations for the 12 months ending March 31, 2005, which reduced operating expense and the regulatory liability by $2.2 million. In total, this amounted to a net $4.4 million charge to earnings.
The Rate Order, with revisions from the PSB's Compliance Order, required a customer refund amounting to about $6.5 million ($3.3 million after-tax), including carrying costs of $0.3 million based on a lump-sum refund. The refund represented over-collections from customers for April 7, 2004 though March 31, 2005 ($1.7 million attributed to 2005 and $4.5 million attributed to 2004). On April 25, 2005, the PSB approved a proposal for a lump-sum refund to customers in June 2005 billings. Additionally, on April 25, 2005, the PSB approved application of the $3.8 million regulatory liability for 2004 overearnings (see discussion of February 18, 2005 Accounting Order above) to the refund liability.

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

In the second quarter of 2005, the Company recorded an additional $0.1 million of interest expense for carrying costs based on the actual date of the refund. The $6.5 million current liability was reversed in the second quarter of 2005, reflecting distribution of the refund in June 2005. The refund applied to customers who were active during the period of over-collection, and most of the refund was made through credits on customer bills.

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

a $2.4 million increase in purchased power expense mostly related to expensing of Yankee Atomic incremental dismantling costs and Vermont Yankee 2004 replacement energy costs to reflect rate recovery beginning April 1, 2004;

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a $3.2 million increase in operating expenses mostly related to amortization of Vermont Yankee (non-tax) sale-related costs, Vermont Yankee 2002 fuel rod costs and Yankee Atomic dismantling costs to reflect rate recovery beginning April 1, 2004;
a $0.8 million decrease in interest income to adjust carrying costs related to Vermont Yankee (non-tax) sale-related costs and Vermont Yankee 2002 fuel rod costs due to rate recovery beginning April 1, 2004;
a $0.4 million increase in other deductions for disallowance of a portion of Vermont Yankee 2002 fuel rod costs; offset by
a $0.4 million decrease in other interest expense related to various other adjustments per the Rate Order.

The Rate Order impact on the Condensed Consolidated Statement of Income for the nine months ended September 30, 2005 is shown in the table below. See Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits for the impact on the Condensed Consolidated Balance Sheet.

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

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

The Company, DPS and AARP submitted their responses to these motions by April 26, 2005 as required by the PSB. On May 25, 2005, the PSB issued its Order on both Motions for Reconsideration. All requests to modify the Rate Order were denied with the exception of a minor modification to one sentence in the Rate Order, and a request for the Company to inform the PSB and other parties on its treatment of construction work in process in the overearnings calculation. That matter has been resolved.

The Company believes the Rate Order results in rates that do not provide sufficient revenue for the Company to recover its ongoing costs of providing adequate and efficient service. Consequently, the Company informally notified the PSB and other parties that it intended to appeal, and on June 22, 2005, the Company filed an appeal of portions of the Rate Order with the Vermont Supreme Court. On July 11, 2005, the Company filed a docketing statement with the court in which it outlined the issues in its case. The docketing statement describes the ordered payback of earnings from periods prior to the opening of the rate investigation, namely the years 2001 to 2003 and also the first quarter of 2004 when the Company recorded a gain from the Connecticut Valley sale. The issues that were raised on appeal primarily focus on whether the Rate Order set rates retroactively without statutory authorization. On July 27, 2005, the DPS filed a response opposing the Company's position. The Company filed its legal brief and other materials in the case on August 22, 2005. The Company proposed to waive oral argument, but the DPS and AARP requested argument. The court approved the Company's request for expedited oral argument which is expected to occur in December 2005 or January 2006. The Company expects a Vermont Supreme Court decision on the case in the second quarter of 2006. The Company is not able to predict the outcome of this matter at this time.

On August 29, 2005, the Company filed a new rate design proposal in compliance with the Rate Order. This proposal maintains the Company's overall revenue requirement approved in the Rate Order, but would reallocate rate class revenue between some rate classes. The proposal includes a 1 percent rate increase for residential Rates 1 and 8, a 2.99 percent increase in off peak water heating Rates 3 and 14 and a 2.83 percent decrease in general service Rate 2. In addition, the Company's proposal includes lower demand charges and higher energy charges for rate classes with those components, which would be revenue neutral for each rate class. Several Vermont ski areas have intervened, and the Company will participate in several workshops to seek a settlement with all parties. If discussions are not successful by January 2006, a schedule for hearings will be determined.

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Income Statement Impacts of the Rate Order:
The table below reflects the impact of the first quarter 2005 Rate Order charge to earnings on specific line items of the Condensed Consolidated Statement of Income for the nine months ended September 30, 2005 on a pre-tax basis (in millions).

Income Statement Line Item
Operating Revenue (#3 above)
Purchased Power (#4 above)
Other Operation (#1, 2, 3 and 4 above)
Other Income (#4 above)
Other Deductions (#4 above)
Other Interest (#1, 3 and 4 above)

Total Rate Order Impact

$(6.2)
(2.5)
(10.7)
(0.8)
(0.4)
(1.2)

$(21.8)

NOTE 9 - COMMITMENTS AND CONTINGENCIES
Maine Yankee, Connecticut Yankee and Yankee Atomic
The Company is responsible for paying its ownership percentage of decommissioning and all other costs for 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 its retail customers through PSB-approved rates. Based on the regulatory process, Management believes its share of decommissioning and closure costs for each plant will continue to be recovered through the regulatory process. Although Management believes that these costs will ultimately be recovered from its customers, there is a risk that FERC may not allow full recovery of Connecticut Yankee's increased costs in wholesale rates, as described below.

The Company's share of Maine Yankee, Connecticut Yankee and Yankee Atomic estimated costs are reflected on the Condensed Consolidated Balance Sheet as regulatory assets and nuclear decommissioning liabilities (current and non-current). These amounts are adjusted when revised estimates are provided by the companies. At September 30, 2005, the Company had regulatory assets of about $5.0 million related to Maine Yankee, $10.9 million related to Connecticut Yankee and $3.5 million related to Yankee Atomic. The regulatory asset balance related to Yankee Atomic includes about $0.8 million for incremental decommissioning costs that have been paid by the Company and are now being recovered in retail rates pursuant to the Rate Order. These estimated costs are being collected from the Company's customers through existing retail rate tariffs. See Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits, regarding the impacts of the Rate Order.

Maine Yankee, Connecticut Yankee and Yankee Atomic are seeking recovery of fuel storage-related costs stemming from the default of the United States Department of Energy ("DOE") under the 1983 fuel disposal contracts that were mandated by the United States Congress under the High Level Waste Act. All three are parties to a lawsuit against the DOE seeking damages based on the DOE's default. Maine Yankee's damage claim is about $160 million, Connecticut Yankee's damage claim is about $197 million and Yankee Atomic's damage claim is about $191 million. None of the plants has included any allowance for potential recovery of these claims in their FERC-filed cost estimates.

The trial on determination of damages began on July 12 and ended August 31, 2004. Closing arguments were held in January 2005 and final post-trial briefs were filed in February 2005. The Department of Justice submitted a motion to the court during the damage trial arguing that the spent fuel obligations prior to April 1983 should be treated as an offset to any award of damages. The Court's ruling on that matter is expected to be issued with its overall ruling in the case, which is expected by the end of 2005.

Maine Yankee: The Company has a 2 percent ownership interest in Maine Yankee. Beginning November 1, 2004, Maine Yankee's billings to sponsor companies have been based on its September 16, 2004 FERC-approved settlement, which provides for recovery of Maine Yankee's forecasted costs of providing service through a formula rate contained in its power contracts through October 31, 2008 and replenishment of the DOE Spent Fuel Obligation through collections from November 2008 through October 2010. On October 3, 2005, Maine Yankee completed its decommissioning efforts and the Nuclear Regulatory Commission ("NRC") amended its operating license for operation of the Independent Spent Fuel Storage Installation.

In October 2005, Maine Yankee provided an updated forecast for ongoing costs which reflects an estimated increase of about $10.1 million. The increase is primarily related to higher than expected interest expense. The Company's share of these estimated increased costs is about $0.2 million.

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

Bechtel Litigation: Connecticut Yankee is involved in a contract dispute with Bechtel Power Corporation ("Bechtel"), which resulted in default termination of the decommissioning services contract between Connecticut Yankee and Bechtel effective July 2003. Connecticut Yankee continues to prosecute its counterclaims for excess completion costs and other damages against Bechtel in Connecticut Superior Court ("Court"). Discovery and depositions are nearly complete in support of a trial scheduled to begin in May 2006.

In the prejudgment remedy proceeding before the Court, Bechtel sought garnishment of the decommissioning trust and related payments. In October 2004, Bechtel and Connecticut Yankee entered into an agreement in which Bechtel agreed to withdraw its request for garnishment of the decommissioning trust and related payments in return for attachment of all real property owned by Connecticut Yankee in Connecticut up to $7.9 million and the escrowing of $41.7 million the sponsors are scheduled to pay to Connecticut Yankee through June 30, 2007 in respect to Connecticut Yankee's common equity. This agreement is subject to the Court's approval and would not be implemented until the Court found that such assets were subject to attachment. Connecticut Yankee has contested the attachability of such assets. The agreement does not materially change the legal positions in this litigation. The Connecticut Department of Public Utility Control ("CT DPUC"), an intervener in this proceeding, did not object to the agreement. The Court has taken no further action.

On September 6, 2005, Connecticut Yankee submitted a summary judgment motion for dismissal of Bechtel's negligent misrepresentation claim. On October 7, 2005, Bechtel filed a motion withdrawing its negligent misrepresentation claim.

FERC Rate Case Filing: Connecticut Yankee's estimated decommissioning and plant closure costs for the period 2000 through 2023 ("2003 estimate") have increased by about $395 million compared to the cost estimate in its 2000 FERC rate case settlement. The revised estimate reflects increased costs including the fact that Connecticut Yankee is now directly managing the work (self-performing) to complete decommissioning of the plant following the default termination of Bechtel. On July 1, 2004, Connecticut Yankee filed the 2003 estimate with FERC as part of its rate application ("Filing") seeking additional funding for recovery of these increased costs. 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 CT DPUC and Bechtel have intervened in this rate case.

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

Both the CT DPUC and Bechtel filed testimony in the FERC proceeding claiming that Connecticut Yankee was imprudent in its management of the decommissioning project. In its February 22, 2005 filed testimony, the CT DPUC recommended a disallowance of $225 million to $234 million out of Connecticut Yankee's $395 million requested increase. The Company's share of the CT DPUC's recommended disallowance is between $4.5 million and $4.7 million.

The June 2005 hearings and the September and October briefing process are complete and an initial decision is expected by mid-December 2005. In the briefing process the DPUC continued to allege imprudence of between $225 million and $234 million. The process of resolving the matters in the Filing is likely to be contentious and lengthy.

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

Yankee Atomic: The Company has a 3.5 percent ownership interest in Yankee Atomic. Costs billed by Yankee Atomic are based on an April 4, 2003 FERC filing, in which FERC approved the resumption of billings starting June 2003 for a recovery period through 2010. The decommissioning effort is largely complete. Following decommissioning, the remaining on-site function will be to operate the Independent Spent Fuel Storage Installation.

Yankee Atomic is preparing an application to FERC for increased decommissioning charges to go into effect in early 2006, subject to FERC acceptance and approval. Yankee Atomic has identified increases in the scope of soil remediation and certain other remediation activities to meet environmental standards, beyond the levels assumed in its previously settled FERC rate case. While the evaluation is not complete, Yankee Atomic has determined that the schedule for completion of physical work will need to extend until mid-2006 and the costs of completing decommissioning will be about $63 million greater than previous estimates. The timing and amount of the FERC application and the increase in decommissioning charges are under development, but Yankee Atomic expects that it will seek rate recovery of a significant component of the increased expenditures during 2006. The Company's share of this increase in decommissioning costs amounts to about $2.2 million. The Company cannot predict the timing and outcome of a FERC proceeding required for collection of the increased Yankee Atomic decommissioning costs, but the Company believes these incremental costs, above costs currently recovered in retail rates, will be recovered in future retail rate proceedings.

Millstone Unit #3

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

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

The Millstone Unit #3 refueling outage was scheduled to begin on October 1, 2005, but instead began on September 29, 2005 when circulating water pumps tripped due to debris in the intake cooling system. The plant was returned to service on October 27. Based on approved regulatory accounting treatment the Company defers the cost of incremental replacement energy and incremental maintenance costs of the scheduled refueling outage, and is allowed to amortize those costs through the next scheduled refueling outage which typically spans over an 18-month period. The Company purchased replacement power through ISO-New England during the outage period. Current estimates related to the outage include about $1.4 million for incremental replacement power costs and $0.5 million for incremental maintenance costs.

Vermont Yankee
The Company has a 35 percent entitlement in Vermont Yankee plant output sold by Entergy Nuclear Vermont Yankee, LLC ("ENVY") to VYNPC, through a long-term power purchase contract ("PPA") with VYNPC. One remaining secondary purchaser continues to receive a small percentage of the Company's entitlement, reducing its entitlement to about 34.83 percent. ENVY has no obligation to supply energy to VYNPC over the amount the plant is producing, so entitlement holders receive reduced amounts when the plant is operating at a reduced level, and no energy when the plant is not operating. Vermont Yankee's next scheduled refueling outage began on October 22, 2005 and the plant is expected to begin production again on November 10, 2005 follwed by a ramp up to full power over about 3 days.

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

The Company is currently seeking recovery from ENVY, under the RPP, for incremental replacement energy costs incurred when the plant was shut down for 19 days beginning in mid-June 2004. The Company believes the plant went off line due to problems associated with uprate-related improvements made by ENVY, and has sought about $0.8 million from ENVY. ENVY contends that the problem would have occurred regardless of the uprate. Having failed to reach a settlement with ENVY, the Company petitioned the PSB for resolution. The Company, Green Mountain Power and ENVY are currently in discussions to settle the matter. Pursuant to the Rate Order, any partial or full reimbursement received by the Company from ENVY under the RPP shall be recorded as a regulatory liability for return to ratepayers in the Company's next rate proceeding.

In April 2004, ENVY reported that two short spent fuel rod segments were not in what ENVY believed to be their documented location in the spent fuel pool. Subsequently, ENVY's continuing documentation review led to the discovery of the fuel rod segments in a container in the spent fuel pool. During that time, ENVY notified VYNPC that based on the terms of the Purchase and Sale Agreement dated August 1, 2001, and facts at the time, it was their view that costs associated with the spent fuel rod segment inspection effort were the responsibility of VYNPC. VYNPC responded that based on the information at the time there was no basis for ENVY's claim. While this matter has not been fully resolved with ENVY, Management does not believe that the Company has any potential liability related to the lost fuel rods.

ENVY has announced that, under current operating parameters, it will exhaust the capacity of its nuclear waste (spent fuel) storage pool in 2007 or 2008 and will need to store nuclear waste in so-called 'dry cask storage' facilities to be constructed on the site. Construction and use of such dry cask storage facilities requires approval from the Vermont State Legislature, in addition to PSB approval. In early June 2005, the Vermont State Legislature passed a law authorizing ENVY to construct and use dry cask storage facilities on the site through its current license. In late June 2005, ENVY filed an application with the PSB for permission to install dry cask storage facilities at the site. In September 2005, ENVY filed notice with the NRC that it intended to seek a license extension for the Vermont Yankee plant. The notice said the plant would seek a 20-year extension, which if approved would allow the plant to operate until 2032.

If ENVY is unsuccessful in receiving regulatory approval for dry cask storage, ENVY has announced that it could be required to shut down the Vermont Yankee plant in 2007 or 2008, instead of its current license life of 2012. If the Vermont Yankee plant is shut down, the Company would lose about 50 percent of its committed energy supply and would have to acquire replacement power resources comprising about 40 percent of its estimated power supply needs. Based on projected market prices, the value of the lost output is estimated to be about $50 million on an annual basis. Based on this estimate, the Company would require a retail rate increase of about 18 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.

Performance Assurance
At September 30, 2005, the Company had posted $21.5 million of collateral under performance assurance requirements for certain of its power contracts. These payments are recorded as Special Deposits on the Condensed Consolidated Balance Sheet. In the second quarter, the PSB provided interim approval to meet collateral requirements on power contracts, with the exception of ISO-New England collateral that it already approved. On October 21, 2005, the Company received final PSB approval to meet collateral requirements associated with power transactions. Performance assurance requirements are described in more detail below.

The Company is subject to performance assurance requirements associated with its power purchase and sale transactions through ISO-New England under the Financial Assurance Policy for NEPOOL members. The Company must post collateral if the net amount owed exceeds its credit limit at ISO-New England. A company's credit limit is calculated as a percentage, based on its credit rating, of its net worth. At the Company's previous credit rating of 'BBB-', the credit limit with ISO-New England was about $2.7 million. At the Company's current credit rating of 'BB+', the credit limit with ISO-New England is zero and the Company is required to post collateral for all net purchase transactions. ISO-New England reviews collateral requirements on a daily basis. As of September 30, 2005, the Company posted $3.9 million of collateral with ISO-New England.

Page 29 of 65

The Company is currently selling power in the wholesale market pursuant to two third-party contracts covering periods through late 2006 and late 2008. Under both of these contracts, the Company is required to post collateral if its credit rating is downgraded below investment-grade status, but only if requested to do so by the counterparties. The Company currently estimates that it could be required to post collateral of up to about $29.0 million under these two contracts, based on current estimates of forward market prices. Depending on the difference between the contract price and the market price of power, this estimate could increase or decrease significantly. As of September 30, 2005, the Company posted $17.6 million of collateral related to one of the third-party contracts. This collateral requirement is reviewed on a weekly basis. At this time, the Company has not been requested to post collateral under the other third-party contract.

The Company is also subject to performance assurance requirements under its Vermont Yankee power purchase contract (the 2001 Amendatory Agreement). If ENVY, the seller, has commercially reasonable grounds for insecurity regarding the Company's ability to pay for its monthly power purchases, ENVY may ask VYNPC and VYNPC may then ask the Company to provide adequate financial assurance of payment. The Company has never had to post collateral under this contract.

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

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

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

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

Dover, New Hampshire, Manufactured Gas Facility In 1999, Public Service Company of New Hampshire ("PSNH") contacted the Company about this site. PSNH alleged that the Company was partially liable for cleanup, since the site was previously operated by Twin State Gas and Electric, which merged into the Company the same day that PSNH bought the facility. In 2002, the Company reached a settlement with PSNH in which certain liabilities it might have had were assigned to PSNH in return for a cash settlement paid by the Company based on completion of PSNH's cleanup effort. The Company's remaining obligation related to this settlement is less than $0.1 million.

As of September 30, 2005, a $5.3 million reserve for environmental matters is recorded on the Condensed Consolidated Balance Sheet. At December 31, 2004, the reserve was $6.1 million. The reserve represents Management's best estimate of the cost to remedy issues at these sites. There is no pending or threatened litigation regarding other sites with the potential to cause material expense. No government agency has sought funds from the Company for any other study or remediation.

Catamount
In September 1995, Catamount's wholly owned subsidiary, Equinox Vermont Corporation, verbally agreed to indemnify Tractebel Power Operations, Inc. ("Tractebel") for up to 33.1126 percent of the amount the actual price of fuel charged to Ryegate Associates (the "Partnership") exceeds the fuel price guaranteed to the Partnership's lender by Tractebel. The fuel price guarantee will expire in 2008. Based on Catamount's long-term forecast for wood fuel prices, Catamount does not anticipate the actual fuel price for the Partnership will exceed the fuel price guaranteed to the Partnership lender through 2008.

Page 30 of 65

In November 2004, Catamount entered into an agreement with a third-party developer for the purchase of wind turbines for a joint development project. Pursuant to the agreement, Catamount made $5.9 million of payments to the turbine supplier in 2004 and $5.9 million in March 2005. When the Sweetwater 3 construction financing closed on May 9, 2005, the remaining contract amount was assumed by the Sweetwater 3 project, pursuant to the construction financing agreement.

NOTE 10 - DISCONTINUED OPERATIONS

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

For accounting purposes, components of the sale transaction are recorded in both continuing and discontinued operations in the first nine months 2004 Condensed Consolidated Statement of Income. Income from discontinued operations included a gain on disposal of about $21 million pre-tax, or $12.3 million after-tax. In addition to the gain on disposal, the Company recorded a loss on power costs of $14.4 million pre-tax, or $8.4 million after-tax relating to termination of the power contract with Connecticut Valley. The loss is included in Purchased Power in the 2004 Condensed Consolidated Statement of Income. When the two accounting transactions are combined to assess the total impact of the sale, the result was a gain of $3.9 million recorded in the first quarter of 2004.

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

Three Months Ended
September 30,
2005                       2004

Nine Months Ended
September 30,
2005                       2004

Operating revenues
Operating expenses
   Purchased power
   Other operating (income) expenses
   Income tax expense (benefit)
   Total operating (income) expenses
Operating income (loss)
Other income, net

Net income, net of tax

Gain from disposal, net of $8,692 tax for nine months ended

Income from discontinued operations, net of tax

$-

-
-
  -
-
  -
  -

-

  -

$-

$

-
(3)
    1
   (2)
    2
     -

2

    6

$8

$-

-
-
  -
-
  -
  -

-

  -

$-

$24

-
40
       (14)
         26
(2)
         22

20

  12,334

$12,354

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

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

Page 31 of 65

Three Months Ended September 30,

CV
VT

Catamount
Energy
Corporation

All Other

Discontinued
Operations

Reclassification
and
Consolidating
Entries

Consolidated

2005

Revenues from external customers
Intersegment revenues
Equity in earnings - utility affiliates (1)
Equity in earnings - non-utility affiliates (2)
Income (loss) from continuing operations
Total assets at September 30, 2005

$75,013
24
485
-
2,871
488,751

$171
-
-
27
(250)
67,379

$470
-
-
-
100
3,953

-
-
-
-
-
-

$(641)
(24)
-
-
-
(1,034)

$75,013
-
485
27
2,721
559,049

2004

Revenues from external customers
Intersegment revenues
Equity income - utility affiliates (1)
Equity income - non-utility affiliates (2)
Income from continuing operations
Income from discontinued operations, net of tax
Total assets at December 31, 2004

$72,740
23
410
-
4,515
-
487,567

$126
-
-
1,145
1,427
-
61,029

$476
-
-
-
115
-
15,247

-
-
-
-
-
8
-

$(602)
(23)
-
-
-
-
(17,080)

$72,740
-
410
1,145
6,057
8
546,763

Nine Months Ended September 30,

CV
VT

Catamount
Energy
Corporation

All Other

Discontinued
Operations

Reclassification
and
Consolidating
Entries

Consolidated

2005

Revenues from external customers
Intersegment revenues
Equity in earnings - utility affiliates (1)
Equity in earnings - non-utility affiliates (2)
Rate Order charge (3)
(Loss) income from continuing operations
Total assets at September 30, 2005

$225,750
69
1,446
-
21,843
566
488,751

$1,598
-
-
1,386
-
(699)
67,379

$1,393
-
-
-
-
317
3,953

-
-
-
-
-
-
-

$(2,991)
(69)
-
-
-
-
(1,034)

$225,750
-
1,446
1,386
21,843
184
559,049

2004

Revenues from external customers
Intersegment revenues
Equity income - utility affiliates (1)
Equity income - non-utility affiliates (2)
Income from continuing operations
Income from discontinued operations, net of tax
Total assets at December 31, 2004

$224,489
69
881
-
5,180
-
487,567

$1,375
-
-
3,747
2,045
-
61,029

$1,421
-
-
-
340
-
15,247

-
-
-
-
-
$12,354
-

$(2,796)
(69)
-
-
-
-
(17,080)

$224,489
-
881
3,747
7,565
12,354
546,763

See Note 2 herein for CV's investments in affiliates.
See Note 3 herein for CV's investment in non-utility affiliates.
See Note 8 herein for Retail Rates.

NOTE 12 - SUBSEQUENT EVENTS

Sale of Controlling Interest in Catamount
On October 12, 2005, the Company entered into a Stock Subscription Agreement (the "Subscription Agreement") among the Company, CEC Wind Acquisition, LLC, a Delaware limited liability company established by Diamond Castle, a New York based private equity investment firm (the "Purchaser"), Catamount Resources Corporation ("CRC"), and Catamount. The Subscription Agreement provides that, upon the terms and subject to the conditions set forth therein, the Purchaser will invest $62.5 million in Catamount for an approximate 51 percent ownership interest in Catamount.

Concurrent with the Subscription Agreement, the Company also entered into a Stockholders' Agreement (the "Stockholders' Agreement") among the Company, CRC, the Purchaser and Catamount. The Stockholders' Agreement governs the Company's and CRC's on-going relationship with the Purchaser as stockholders of Catamount and provides, among other things, CRC with the option to sell to the Purchaser its entire remaining interest in Catamount, with such option exercisable by CRC on or before March 31, 2006 subject to certain terms and conditions, for an aggregate consideration of $60.0 million less certain transaction expenses.

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At the initial closing, which occurred on October 31, 2005, the Purchaser paid $16.0 million for 160,000 shares of Class A common stock, par value $0.01 per share, (representing approximately 21 percent of the outstanding common equity of Catamount) and 1 share of Class B common stock, par value $0.01 per share, of Catamount. The share of Class B common stock, together with their Class A common stock, give the Purchaser an approximate 51 percent voting interest in Catamount. CRC retains the remaining voting interest in Catamount. The Purchaser's investment will occur in phases, over the next three years, to provide equity as needed to Catamount for it to continue its wind energy development activities in the United States and United Kingdom.

The Company is completing its evaluation of the accounting implications of the transaction if it decides to sell all of its interest in Catamount. The transaction including related transaction costs will be recorded in the fourth quarter of 2005.

Utility Credit Facility
On October 27, 2005, the Company closed a three-year, $25.0 million unsecured revolving credit facility with a lending institution, pursuant to a Credit Agreement dated as of October 21, 2005. On September 30, 2005, the PSB had issued an order approving the credit facility. The purpose of the credit facility is to provide liquidity for general corporate purposes, including working capital needs and power contract performance assurance requirements in the form of borrowings and letters of credit. The Company anticipates that the need to provide collateral for power transactions will be the principal use of the credit facility, although the Company may draw on it, from time to time, to meet short-term capital needs. Financing terms and costs include an annual commitment fee on the unused balance, plus an interest amount on the outstanding balance of borrowings and letters of credit that is based on the Company's unsecured long-term debt rating, which is equivalent to the Company's corporate credit rating. Terms also include the requirement to collateralize any outstanding letters of credit in the event of a default under the credit facility. The Company is currently seeking PSB approval to provide collateral in this circumstance. Until such approval, the Company will not issue letters of credit under this credit facility.

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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.
In this section we discuss the general financial condition and results of operations for Central Vermont Public Service Corporation (the "Company" or "we" or "our" or "us") and its subsidiaries. Certain factors that may impact future operations are also discussed. Our discussion and analysis is based on, and should be read in conjunction with, the accompanying Condensed Consolidated Financial Statements.

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

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

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

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

Our third quarter 2005 earnings were $2.7 million, or 21 cents per diluted share of common stock, compared to third quarter 2004 earnings of $6.1 million, or 47 cents per diluted share of common stock. Our year-to-date earnings were $0.2 million, or a 1 cent loss per diluted share, compared to earnings of $19.9 million, or $1.56 per diluted share of common stock, for the same periods in 2004. Our year-to-date 2005 results include a $21.8 million pre-tax charge to earnings related to the March 29, 2005 Rate Order. We have appealed certain portions of the Rate Order with the Vermont Supreme Court and expect a decision in that case in the second quarter of 2006. See discussion of Retail Rates below.

Pursuant to the Rate Order our retail rates were reduced by 2.75 percent beginning April 1, 2005, our allowed return on equity was reduced from 11 percent to 10 percent, and we refunded customers about $6.5 million in June 2005. In October 2005 we closed on a $25 million credit facility to help ensure liquidity is maintained over the near term. However, without a combination of ongoing cost reductions and a rate increase within the next 18 months, our ongoing liquidity will be greatly impacted.

In June 2005, Standard & Poor's Ratings Services ("S&P") lowered our corporate credit rating to below investment grade. Fitch also lowered its ratings on our senior secured debt and preferred stock. These actions were taken as a result of the Rate Order. As a result of the downgrades, we were required to post $21.5 million of collateral under performance assurance requirements for certain of our power contracts as of September 30, 2005. Additionally, in October 2005 we were required to pre-pay about $15 million related to the forward purchase of replacement power for Vermont Yankee's scheduled refueling outage that began on October 22, 2005.

Page 34 of 65

Two events occurred in October 2005 that are expected to increase costs in the fourth quarter of 2005. One was a massive storm fueled by Hurricane Wilma that dumped dense snow on our service territory taking down thousands of trees and causing about 40,000 of our customers to lose power. We were assisted by 35 tree crews and 29 contracted line crews in addition to our own line crews and dozens of support staff in restoring service to our customers. This massive restoration effort is expected to cost between $1.2 million and $1.5 million on a pre-tax basis. The other was the purchase of replacement power for the Vermont Yankee plant refueling outage that began on October 22, 2005. These purchases were made at significantly higher prices than what we currently recover in retail rates. We may seek an accounting order for deferral of those incremental costs. See Power Supply Matters below for additional information.

We are continuing to identify opportunities to help reduce the impact of the rate reduction and customer refund, and will continue to seek out additional cost reduction opportunities going forward. At some point, given inflationary cost pressures, we will have to file a new rate case. We are currently analyzing forecast information to determine the appropriate timing of a new rate case.

After the issuance of the Rate Order, we decided not to make additional equity investments in Catamount in 2005. In July 2005, Catamount repaid the $12.8 million bridge loan that we had extended in April 2005. In July 2005, Catamount closed on a $31.0 million credit facility that is non-recourse to us. On October 12, 2005, we reached an agreement to sell a controlling interest in Catamount to Diamond Castle, a New York-based private equity investment firm ("Diamond Castle"). Over the next three years Diamond Castle will make a series of equity investments in Catamount, totaling $62.5 million. This capital will allow Catamount to fully develop all of the opportunities in its project pipeline, without requiring any additional cash investment from us until Diamond Castle meets its $62.5 million commitment. The agreements with Diamond Castle also include an option for us to sell all of our interest in Catamount for $60.0 million less certain transaction expenses.

Catamount received Diamond Castle's initial investment of $16.0 million on October 31, 2005 and Diamond Castle received 21 percent equity ownership and a majority of the voting rights in Catamount. Diamond Castle's ownership level will increase as additional payments are made, and eventually will equal 51 percent. As a 49 percent owner in a business that will be twice its original size, we believe the potential remains for us to receive earnings contributions from Catamount over the next few years, consistent with original projections.

We are currently considering whether selling the remaining 49 percent of Catamount or remaining as a part owner, will serve our shareholders best over the long term. See Sale of Controlling Interest in Catamount below.

Our investment plans related to Vermont Electric Power Company ("VELCO") have not changed. In 2004, we invested about $7.0 million in VELCO's planned transmission system upgrades. We planned to make an additional investment of $5.7 million in the third quarter of 2005, but VELCO is currently assessing the timing of its equity needs, which is now expected to be in 2006. Our Board of Directors will continue to review this commitment on a quarterly basis to determine the appropriate level of ongoing support to VELCO.

These matters are discussed in more detail in Liquidity and Capital Resources below.

SALE OF CONTROLLING INTEREST IN CATAMOUNT
On October 12, 2005, we entered into a Stock Subscription Agreement (the "Subscription Agreement") with CRC, Catamount and CEC Wind Acquisition, LLC, a Delaware limited liability company established by Diamond Castle. The Subscription Agreement provides that, upon the terms and subject to the conditions set forth therein, Diamond Castle will invest $62.5 million in Catamount over the next three years for an approximate 51 percent ownership interest in Catamount when the $62.5 million investment is complete.

Concurrent with the Subscription Agreement, the parties also entered into a Stockholders' Agreement ("Stockholders' Agreement") that governs CRC and our on-going relationship with Diamond Castle as stockholders of Catamount and provides, among other things, CRC with the option to sell to Diamond Castle its entire voting interest in Catamount, with such option exercisable by CRC on or before March 31, 2006 subject to certain terms and conditions, for an aggregate consideration of $60.0 million less certain transaction expenses.

At the initial closing, which occurred on October 31, 2005, Diamond Castle paid $16.0 million to Catamount for 160,000 shares of Class A common stock, par value $0.01 per share, (representing about 21 percent of the outstanding common equity of Catamount) and 1 share of Class B common stock, par value $0.01 per share, of Catamount. The share of Class B common stock, together with Diamond Castle's Class A common stock, gives

Page 35 of 65

Diamond Castle an approximate 51 percent voting interest in Catamount. CRC retains the remaining 49 percent voting interest in Catamount. The Class B share will convert to a single share of Class A Common stock in certain circumstances, including default by Diamond Castle in its funding obligations. If this occurs, Diamond Castle will no longer have a 51 percent voting interest in Catamount.

Pursuant to the Stockholders' Agreement, on October 31, 2005, Catamount's Board of Directors was restructured to consist of seven directors, including three directors appointed by the Company, three directors appointed by Diamond Castle and the Chief Executive Officer of Catamount. Subject to certain conditions, under the Stockholders' Agreement, certain actions may only be taken by Catamount with the prior consent of Diamond Castle and us, including, among others, (i) amending the charter or by-laws in such a manner that could adversely affect such party; (ii) approving affiliate transactions between Catamount and any related party; (iii) approving the annual budgets, provided that Diamond Castle will have the sole discretion over the use of its funds prior to the full funding of the $62.5 million; (iv) issuing new debt or equity not specified in the annual budget; (v) declaring dividends or other distributions; (vi) removing or appointing the chief executive officer; and (vii) making significant, defined as more than $10 million, acquisitions or divestitures, other than the initial $62.5 million or as contemplated by the annual budget.

Under the terms of the Subscription Agreement, we agreed to indemnify Catamount and Diamond Castle, 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. We have indemnified all losses related to taxes for periods prior to the initial closing, subject to a "true up" post-closing. Indemnification is net of insurance and taxes, and materiality is disregarded from all representations and warranties. Indemnification is subject to a $1.5 million deductible and a $15 million cap, excluding certain customary items. Environmental representations are subject to the deductible and the cap, and such environmental representations for only two of Catamount's underlying energy projects survive beyond June 30, 2007. We are not aware of any claim for indemnification at this time.

This new partnership, once Diamond Castle completes its $62.5 million investment, will effectively double the size of Catamount. We are currently considering whether selling the remaining 49 percent of Catamount or remaining as a part owner, will serve our shareholders best over the long term.

We are completing our evaluation of the accounting implications of the transaction if we decide to sell all of our remaining interest in Catamount. The transaction including related transaction costs will be recorded in the fourth quarter of 2005.

Also, see Diversification below for additional information related to Catamount.

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

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

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

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

On March 29, 2005, the PSB issued its Order ("Rate Order") on the rate investigation and our request for a rate increase. The PSB concluded that our rates were higher than is just and reasonable, and must be reduced. In the Rate Order, the PSB determined the annual revenue requirement for the period beginning April 1, 2004, established rates retroactive to April 7, 2004 and established new rates beginning April 1, 2005. The Rate Order included, among other things, the following: 1) a 1.88 percent rate reduction beginning April 1, 2005; 2) a $3.3 million 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. We were also required to file a compliance filing by April 1, 2005, which we did, and file a new rate design within 90 days of the Rate Order. The PSB subsequently approved our request for an extension on the rate design filing until August 29, 2005.

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

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

Per our July 2001 PSB-approved rate settlement, utility earnings were capped at 11 percent for the periods 2001 - 2003. We used a common-equity-based calculation methodology to calculate utility earnings for those periods, which resulted in overearnings of $0 in 2001, $0.7 million in 2002 and $2.5 million in 2003. In 2002 and 2003, we reduced utility earnings to achieve the 11 percent cap and recorded offsetting regulatory liabilities to be addressed in the next rate proceeding. In the Rate Order, the PSB determined that while our calculation methodology was not incorrect and was reasonable given the language in the 2001 rate settlement, a cost-of-service based calculation methodology was more consistent with traditional ratemaking practice. Therefore, the PSB required that we recalculate utility earnings for 2001 - 2003 using a cost-of-service-based methodology. Based on the recalculation, utility earnings above the 11 percent cap amounted to $2.9 million in 2001, $5.7 million in 2002 and $5.3 million in 2003. The difference in methodologies resulted in overearnings of $10.8 million plus $1.3 million in additional carrying costs for the period 2001 - 2003. The Rate Order requires that we amortize the resulting $15.3 million regulatory liability, which includes amounts previously deferred, over a four-year period ($3.8 million annually) beginning April 1, 2004.

In the first quarter of 2005, we recorded a net $8.3 million charge to earnings. This included a $10.8 million charge to operating expense and $1.3 million to interest expense, offset by amortization of $3.8 million.
Per the Rate Order, we are required to apply the 2004 gain that resulted from termination of the power contract with Connecticut Valley to the benefit of ratepayers through amortizations over a three-year period beginning April 1, 2004. The PSB determined that ratepayers should be compensated for additional costs resulting from the Connecticut Valley sale, because a portion of these costs were included for recovery in the annual revenue requirement beginning April 1, 2004 and the new rates beginning April 1, 2005. The additional costs represent common infrastructure costs that were previously allocated or charged to Connecticut Valley through a service contract.

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

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

The Rate Order, with revisions from the PSB's Compliance Order, required a customer refund amounting to about $6.5 million ($3.3 million after-tax) including carrying costs of $0.3 million based on a lump-sum refund. The refund represented over-collections from customers for April 7, 2004 though March 31, 2005 ($1.7 million attributed to 2005 and $4.5 million attributed to 2004). On April 25, 2005, the PSB approved a proposal for a lump-sum refund to customers in June 2005 billings. Additionally, on April 25, 2005, the PSB approved application of the $3.8 million regulatory liability for 2004 overearnings (see discussion of February 18, 2005 Accounting Order above) to the refund liability.

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

In the second quarter of 2005, we recorded an additional $0.1 million of interest expense for carrying costs based on the actual date of the refund. The June 2005 refund applied to customers who were active during the period of over-collection, and most of the refund was made through credits on customer bills.
Other adjustments required in the Rate Order resulted in a $6.4 million unfavorable effect on utility earnings in the first quarter of 2005. These adjustments were primarily related to adjusting and amortizing certain deferred charges and credits beginning April 1, 2004, because the PSB included recovery of these costs in determining the annual revenue requirement for April 1, 2004 through March 31, 2005. Amortizations result in the matching of expenses to the period in which the amounts are recovered in rates. The primary components of the net $6.4 million charge to earnings were as follows:

a $2.4 million increase in purchased power expense mostly related to expensing of Yankee Atomic incremental dismantling costs and Vermont Yankee 2004 replacement energy costs to reflect rate recovery beginning April 1, 2004;
a $3.2 million increase in operating expenses mostly related to amortization of Vermont Yankee (non-tax) sale-related costs, Vermont Yankee 2002 fuel rod costs and Yankee Atomic dismantling costs to reflect rate recovery beginning April 1, 2004;
a $0.8 million decrease in interest income to adjust carrying costs related to Vermont Yankee (non-tax) sale-related costs and Vermont Yankee 2002 fuel rod costs due to rate recovery beginning April 1, 2004;
a $0.4 million increase in other deductions for disallowance of a portion of Vermont Yankee 2002 fuel rod costs; offset by
a $0.4 million decrease in other interest expense related to various other adjustments per the Rate Order.

The Rate Order impact on the Condensed Consolidated Statement of Income for the nine months ended September 30, 2005 is shown in the table below. Also see Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits for the impact on the Condensed Consolidated Balance Sheet.

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

On April 12, 2005, the DPS filed with the PSB a Motion for Reconsideration of the Rate Order. Specific items for reconsideration included: 1) treatment of costs formerly recovered by the Company through a service contract with Connecticut Valley; and 2) certain adjustments related to the calculation of overearnings for 2001 - 2003.
We, the DPS and AARP submitted responses to these motions by April 26, 2005 as required by the PSB. On May 25, 2005, the PSB issued its Order on both Motions for Reconsideration. All requests to modify the Rate Order were denied with the exception of a minor modification to one sentence in the Rate Order, and a request for us to inform the PSB and other parties on treatment of construction work in process in the overearnings calculation. That matter has been resolved.

We believe the Rate Order results in rates that do not provide sufficient revenue for the Company to recover its ongoing costs of providing adequate and efficient service. Consequently, we informally notified the PSB and other parties that we intended to appeal, and on June 22, 2005, we filed an appeal of portions of the Rate Order with the Vermont Supreme Court. On July 11, 2005, we filed a docketing statement with the court in which we outlined the issues in our case. The docketing statement describes the ordered payback of earnings from periods prior to the

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opening of the rate investigation, namely the years 2001 to 2003 and also the first quarter of 2004 when we recorded a gain from the Connecticut Valley sale. The issues that were raised on appeal primarily focus on whether the Rate Order sets rates retroactively without statutory authorization. On July 27, 2005, the DPS filed a response opposing our position. We filed our legal brief and other materials in the case on August 22, 2005. We proposed to waive oral argument, but the DPS and AARP requested argument. The court has approved our request for expedited oral argument which is expected to occur in December 2005 or January 2006. We expect a Vermont Supreme Court decision on the case in the second quarter of 2006. We are not able to predict the outcome of this matter at this time.

On August 29, 2005, we filed a new rate design proposal in compliance with the Rate Order. This proposal maintains our overall revenue requirement approved in the Rate Order, but would reallocate rate class revenue between some rate classes. The proposal includes a 1 percent rate increase for residential Rates 1 and 8, a 2.99 percent increase in off peak water heating Rates 3 and 14 and a 2.83 percent decrease in general service Rate 2. In addition, our proposal includes lower demand charges and higher energy charges for rate classes with those components, which would be revenue neutral for each rate class. Several Vermont ski areas have intervened, and we will participate in several workshops to seek a settlement with all parties. If discussions are not successful by January 2006, a schedule for hearings will be determined.

LIQUIDITY AND CAPITAL RESOURCES
At September 30, 2005, we had cash and cash equivalents of $11.5 million included in total working capital of $81.2 million. During the first nine months of 2005, cash and cash equivalents decreased by $0.2 million. The decrease resulted from the following:

Operating Activities:  Operating activities provided $6.0 million, including $4.1 million of distribution of earnings from Catamount projects, $1.5 million of dividends from utility investments, $1.4 million provided by deferred revenue related to Catamount's investment in Sweetwater 2 and $1.1 million related to our portion of an IRS tax settlement at VYNPC, partially offset by $21.5 million used to meet performance assurance requirements under power transaction agreements, $6.4 million of income tax payments net of refunds and $5.4 million of net interest payments. In the second quarter of 2005, customer refunds related to the Rate Order were $6.5 million. The majority of this amount was credited to customer bills and reduced cash flows in the third quarter of 2005. Also, in the third quarter of 2005, we contributed $4.5 million to Pension and Postretirement trust funds, in addition to Postretirement out-of-pocket payments of $1.4 million for the first nine months of 2005.

Investing Activities:  Investing activities used $10.9 million including $17.0 million of non-utility investments, $11.3 million of construction expenditures, $22.4 million of restricted cash related to construction of Sweetwater 3 and $4.0 million related to Catamount notes receivable, partially offset by $22.8 million Catamount note repayments related to the Sweetwater 2 project, a $5.2 million Catamount note repayment related to the Sweetwater 3 project, $13.2 million for net sales of available-for-sale securities and $2.5 million of return of capital from certain Catamount projects.

Financing Activities:  Financing activities provided $4.7 million primarily related to issuance of Catamount long-term debt of $14.4 million, offset by $9.1 million of dividends paid on common and preferred stock. Restricted cash provided $2.0 million to retire preferred stock.

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At September 30, 2005, investments in available-for-sale securities included $18.6 million with maturities from 90 days to one year and $8.9 million with maturities greater than one year.

VELCO:  We continue to consider additional investments in VELCO's planned transmission upgrades. Our investments in VELCO will maintain VELCO's common equity at 25 percent of its total capitalization. VELCO will require additional equity capital beyond 2005 in order to finance all of the proposed transmission upgrades and we will consider additional investments in VELCO at that time. We had planned to make an additional investment of $5.7 million in the third quarter of 2005, but VELCO is currently assessing the timing of its equity needs, which is now expected to be in 2006. In total, our investments in VELCO could amount to between $35 million and $40 million through 2008. Our investment plans in VELCO are subject to change due to liquidity deterioration resulting from the Rate Order.

Catamount:  Catamount has sufficient cash flow to cover its ongoing operating expenses. After the issuance of the Rate Order, we decided not to make additional equity investments in Catamount in 2005. In July 2005, Catamount repaid the $12.8 million bridge loan that we had extended in April 2005. In July 2005, Catamount closed on a $31.0 million credit facility that is non-recourse to us. On October 12, 2005, we reached an agreement to sell a controlling interest in Catamount to Diamond Castle, a New York-based private equity investment firm. Over the next three years Diamond Castle will make a series of equity investments in Catamount, totaling $62.5 million. This capital will allow Catamount to fully develop all of the opportunities in its project pipeline, without requiring any additional cash investment from us until Diamond Castle meets its $62.5 million commitment. The initial closing occurred on October 31, 2005, and at that time our voting interest in Catamount was reduced from 100 percent to 49 percent. The agreements with Diamond Castle include an option for us to sell all of our interest in Catamount. See Sale of Controlling Interest in Catamount for additional information.

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

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

We believe that cash on hand, including available-for-sale securities, and cash flow from operations will be sufficient to fund our business for the near term, although Vermont utility cash flow from operations has decreased in 2005 compared to 2004. However, an extended Vermont Yankee plant outage or similar event could significantly impact our liquidity due to the continued high cost of replacement power and performance assurance collateral requirements arising from purchases through ISO-New England or third parties. In the event of an extended Vermont Yankee plant outage, we could seek emergency rate relief from our regulators. Other material risks to cash flow from operations include: loss of retail sales revenue from unusual weather; slower-than-anticipated load growth and unfavorable economic conditions; increases in net power costs largely due to lower-than-anticipated margins on sales revenue from excess power or an unexpected power source interruption; required prepayments for power purchases; and increases in performance assurance collateral requirements described below, primarily as a result of high power market prices.

Financing
Utility Based on outstanding debt at September 30, 2005, no principal payments are due on long-term debt from 2005 through 2007. Substantially all utility property and plant are subject to liens under the First Mortgage Bond indenture. Currently, we are not in default under any of our debt financing documents.

At September 30, 2005, we were in compliance with all covenants related to our various debt agreements, Articles of Association and letters of credit; these agreements contain both financial and non-financial covenants. In the second quarter of 2005, we paid a consent fee of about $0.2 million to our bondholders in exchange for waiver of any interest coverage default that could result from the first quarter 2005 Rate Order charge.

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 expire on November 30, 2005. On September 30, 2005, we received PSB approval to extend these letters of credit for another year. Also on September 30, 2005, these letters of credit were extended by the bank to November 30, 2006.

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Because of our non-investment grade credit rating, the bank required that these letters of credit now be secured under our first mortgage indenture. At September 30, 2005, there were no amounts outstanding under these letters of credit.
On October 27, 2005, we closed on a three-year, $25.0 million unsecured revolving credit facility with a lending institution pursuant to a Credit Agreement dated October 21, 2005. On September 30, 2005, the PSB issued an order approving our entering into the credit facility. The purpose of the facility is to provide liquidity for general corporate purposes, including working capital needs and power contract performance assurance requirements, in the form of borrowings and letters of credit. We anticipate that the need to provide collateral for power transactions will be the principal use of the facility, although we may utilize the credit facility to meet short-term capital needs. Financing terms and costs include an annual commitment fee on the unused balance, plus interest on the outstanding balance of borrowings and letters of credit that is based on our unsecured long-term debt rating. Terms also include the requirement to collateralize any outstanding letters of credit in the event of a default under the credit facility. We are currently seeking PSB approval to provide collateral in this circumstance. Until such approval, we will not issue letters of credit under this credit facility.

Non-Utility The construction financing on a 135-MW windfarm located in Nolan County, Texas, known as Sweetwater 3 wind project ("Sweetwater 3") closed on May 9, 2005 and as a result Catamount posted $24.8 million of security, representing Catamount's expected equity contribution, to be maintained in pledged collateral accounts for the construction lender. Two pledged collateral accounts were established pursuant to the terms of the security account agreement with the construction lender. One of the accounts was funded with $16.4 million and will be drawn upon when all conditions precedent to the Sweetwater 3 equity close have been achieved. The second account was funded with $8.4 million and will be drawn upon to pay construction costs. As the funds are drawn from this account, a note receivable with Sweetwater 3 will be created. When the equity close occurs, Catamount will receive credit against its equity commitment for the full amount of the note receivable. When the construction financing closed in May 2005, Catamount was reimbursed by Sweetwater 3 for cumulative payments of $11.8 million made through March 2005 under the turbine supply agreement described below and $0.2 million for other Sweetwater 3 related project costs. Catamount funded the $24.8 million security with the $12.0 million reimbursements and $12.8 million bridge loan we extended in April 2005.

In November 2004, Catamount entered into an agreement with a third-party developer for the purchase of wind turbines for a joint development project. Pursuant to the agreement, Catamount made $5.9 million of payments to the turbine supplier in 2004 and $5.9 million in March 2005. When the Sweetwater 3 construction financing closed on May 9, 2005, the remaining contract amount was assumed by the Sweetwater 3 project, pursuant to the construction financing agreement.

On July 12, 2005, Catamount Sweetwater Holdings, LLC (the "Borrower"), a wholly owned subsidiary of Catamount, entered into a senior secured Financing Agreement (the "Facility") for up to about $31.0 million of loan commitments with two lenders. The total loan commitment is comprised of a $14.4 million Tranche A amount based on the Borrower's wholly owned subsidiaries' equity interests in the Sweetwater 1 and 2 operating wind projects and a $16.5 million Tranche B amount based on the Borrower's wholly owned subsidiaries' equity interests anticipated in Sweetwater 3, currently under construction and scheduled to be operating in late December 2005 or early January 2006. The actual Tranche B amount will be based on the final economics for Sweetwater 3 when it is placed in commercial operation.

The maturity date for each Tranche is based on the date cash distributions are made under the Facility. The Sweetwater 1 and 2 maturity dates are anticipated to be no later than December 2013 and December 2012, respectively, for an expected average outstanding borrowing of 8.5 years from the borrowing date. The Sweetwater 3 maturity date is anticipated to be no later than December 2012, for an expected outstanding borrowing of seven years from the borrowing date. The Tranche A and B borrowings are priced at a variable interest rate based on the three month LIBOR (London Interbank Overnight Rates). Upon the close of the Facility (July 12, 2005), the Borrower entered into a fixed interest rate swap agreement with the lenders for 75 percent of the total Facility to mitigate interest variability risk.

The Tranche A borrowing occurred upon close of the Facility and Tranche B borrowing will be available through December 2006, which is about one year from the anticipated commercial operation date of Sweetwater 3. All cash distributions from the respective projects received by each of the Borrower's wholly owned subsidiaries will be applied to the outstanding loans based on the maximum permitted loan balance at each scheduled repayment date for each Tranche. If the cash distributions are greater than the amount due at each scheduled repayment date, then the amount in excess of the amount due will be held in a fixed reserve account to be used at future scheduled repayment dates or until such time as the Facility is paid in full.

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The Facility is secured by a first-priority lien on all of the Borrower's wholly owned subsidiaries' membership interests in the Sweetwater 1 and 2 wind projects. If the Tranche B borrowings are activated, then Sweetwater 3 will be subject to a first-priority lien under the Facility. The Facility has limited recourse to Catamount, but only in the event of the loss of certain production tax credits, loss of cash distributions and other matters as defined in the Facility. The Facility is non-recourse to us.

On July 12, 2005, Catamount borrowed $14.4 million under the Facility and used the proceeds to pay off the $12.8 million bridge loan that we extended in April 2005. The remaining amount was used to fund the required debt service reserve account and pay certain transaction costs.

Capital Commitments and Contractual Obligations
Catamount's Facility is summarized in the table below.

Contractual Obligations	Payments Due by Period (in millions)
Contractual Obligations	Total	Less than 1 year	1 - 3 years	3 - 5 years	After 5 years
Long-term debt - non-utility	$13.8	-	$2.2	$3.7	$7.9

Credit Ratings
On April 4, 2005, S&P placed our corporate credit rating on CreditWatch with negative implications. On June 10, 2005, S&P lowered our corporate credit rating from an investment grade of 'BBB-' to 'BB+', which is below investment grade. S&P also lowered the ratings on our senior secured debt from 'BBB+' to 'BBB' which is investment grade, and our preferred stock from 'BB' to 'BB-', which is below investment grade. S&P's rationale for the downgrade was in response to the March 2005 Rate Order. S&P said, "The rate order represents an adverse shift in the company's regulatory environment, which heightens its business risk for the foreseeable future." S&P also removed the rating from CreditWatch and changed the outlook from 'negative' to 'stable' saying "the stable outlook reflects the expectation that the company's financial profile will not deteriorate beyond current projections."

On June 16, 2005, Fitch lowered our senior secured debt from 'BBB+' to 'BBB', which is investment grade; and lowered the preferred stock rating from 'BBB-' to 'BB+', which is below investment grade. Fitch said "The rating downgrade reflects the negative impact of the recent rate decision . . . and the increased business risk resulting from the uncertain regulatory environment."

The downgrades could hamper our operational flexibility by restricting or increasing the cost of future access to capital and imposing additional requirements to provide performance assurance associated with certain power purchase and sale transactions. The downgrades may also increase the annual costs of our three letters of credit and our vehicle lease costs by about $0.1 million.

Performance Assurance
As of September 30, 2005, we had posted $21.5 million of collateral under performance assurance requirements for certain of our power contracts, primarily as a result of the downgrades. In the second quarter, we obtained interim approval from the PSB to meet collateral requirements on power contracts, with the exception of ISO-New England collateral, which had already been approved by the PSB. Final PSB approval to meet collateral requirements associated with power transactions was received on October 21, 2005. 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. We must post collateral if the net amount owed exceeds our credit limit at ISO-New England. A company's credit limit is calculated as a percentage, based on its credit rating, of its net worth. At our previous credit rating of 'BBB-', our credit limit with ISO-New England was about $2.7 million. 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, 2005, we had posted $3.9 million of collateral with ISO-New England.

We are currently selling power in the wholesale market pursuant to two third-party contracts covering periods through late 2006 and late 2008. Under both of these contracts, we are required to post collateral if our credit rating is downgraded below investment-grade status, but only if requested to do so by the counterparties. We estimate that we could be required to post collateral of up to about $29.0 million under these two contracts, based on current

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estimates of forward market prices. Depending on the difference between the contract price and the market price of power, this estimate could increase or decrease significantly. As of September 30, 2005, we posted $17.6 million of collateral related to one of the third-party contracts. This collateral requirement is reviewed on a weekly basis. At this time, we have not been requested to post collateral under the other third-party contract.

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

In anticipation of the Vermont Yankee scheduled refueling outage that began on October 22, 2005, we bought replacement power on a forward basis. As a result of the recent downgrades, the counter party required that we prepay about $15 million for the power purchased, which we did in October 2005.

Future risks to performance assurance requirements include a collateral call under our second forward sale power contract; 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.

OTHER BUSINESS RISKS
In addition to the risks described in Liquidity and Capital Resources above, we are also subject to regulatory risk and wholesale power market risk related to our Vermont electric utility business. These are described in more detail below.

Regulatory Risk: Historically, electric utility rates in Vermont have been based on a utility's costs of service. As a result, electric utilities are subject to certain accounting standards that apply only to regulated businesses. SFAS No. 71 allows regulated entities, in appropriate circumstances, to establish regulatory assets and liabilities, and thereby defer the income statement impact of certain costs and revenues that are expected to be realized in future rates. The Company currently complies with the provisions of SFAS No. 71 for its regulated Vermont service territory and FERC-regulated wholesale businesses. If we determine the Company no longer meets the criteria under SFAS No. 71, the accounting impact would be an extraordinary charge to operations of about $34.0 million on a pre-tax basis as of September 30, 2005, assuming no stranded cost recovery would be allowed through a rate mechanism.

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

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

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 Annual Report filed on Form 10-K for a discussion of the estimates and judgments necessary in our accounting for regulation, unregulated business, revenues, income taxes, loss accruals, pension and postretirement benefits and other matters. The following is an update to the 2004 Form 10-K.

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Regulation We prepare our financial statements in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71, Accounting for the Effects of Certain Types of Regulation ("SFAS No. 71"), for our regulated Vermont service territory and FERC-regulated wholesale business. Although the Rate Order had a significant unfavorable effect on our financial position and results of operations for the period ended September 30, 2005, our regulatory business continues to meet the criteria for accounting under SFAS No. 71. Based on a current evaluation of the factors and conditions expected to impact future cost recovery, Management believes future recovery of its regulatory assets in the State of Vermont for its retail and wholesale businesses is probable.

Unregulated Business Catamount evaluates the carrying value of its investments on a quarterly basis, or when events and circumstances warrant. The carrying value is considered impaired when the anticipated fair value, based on undiscounted cash flows, is less than the carrying value of each investment. In that event, a loss is recognized based on the amount by which the carrying value exceeds the fair value of the investment. Information regarding certain of Catamount's investments follows. See Diversification below for additional information.

Investments in Marketable Securities We account for investments in marketable equity and debt securities in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities ("SFAS No. 115"). At September 30, 2005, all of our marketable securities, except money market funds included in cash and cash equivalents, were classified as available-for-sale and reported at fair value. Unrealized gains and losses are reported as a component of accumulated other comprehensive income, net of tax, in common stock equity. The carrying cost of debt securities is adjusted for amortization of premiums and accretion of discounts from the date of purchase to maturity.

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

We use several criteria to evaluate other-than-temporary declines, including: 1) length of time and the extent to which the market value has been less than cost; 2) financial condition and near-term prospects of the issuer; and 3) our intent and ability to retain the investments for a period of time sufficient to allow for any anticipated recovery in market value. In the first quarter of 2005, we recorded $0.1 million of realized losses and $0.3 million for impairment of certain available-for-sale investments based on our intent to liquidate certain securities prior to their original maturity dates. Based upon forecasted cash flow needs at that time, the security closest to its maturity was chosen. Generally, a security close to its maturity date should have less pricing volatility due to interest rate movements than one further from its maturity date. In the second and third quarters of 2005, we determined that there was no further impairment related to these investment securities. See Note 5 - Investment Securities for additional information.

Pension and Postretirement Benefits Pension costs were $1.1 million in the third quarter and $3.3 million for the first nine months of 2005. Of these amounts, $0.9 million is reflected in results of operations in the third quarter and $2.8 million for the nine months, with the remaining amounts capitalized. This compares to pension costs of $0.8 million in the third quarter of 2004 and $2.4 million for the first nine months of 2004. Of these amounts, $0.7 million was reflected in results of operations in the third quarter and $2.0 million for the nine months, with the remaining amounts capitalized.

Postretirement costs were $0.7 million in the third quarter and $2.1 million for the first nine months of 2005. Of these amounts, $0.6 million is reflected in results of operations in the third quarter and $1.8 million for the nine months, with the remaining amounts capitalized. This compares to postretirement costs of $0.8 million in the third quarter of 2004 and $2.5 million for the first nine months of 2004. Of these amounts, $0.7 million was reflected in results of operations in the third quarter and $2.1 million for the nine months, with the remaining amounts capitalized.

Pension costs and cash funding requirements are expected to increase in future years. As of September 30, 2005, the market value of pension plan trust assets was $67.8 million, including $46.6 million in marketable equity securities and $21.2 million in debt securities. Pension plan trust assets were $64.2 million at December 31, 2004, including $44.3 million in marketable equity securities and $19.9 million in debt securities. The fair value of Postretirement Plan trust assets was $6.2 million at September 30, 2005, compared to $5.0 million at December 31, 2004.

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Derivative Financial Instruments
Power Contracts: We account for various power contracts as derivatives under the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted and SFAS No. 149, Amendment of Statement 133 Derivative Instruments and Hedging Activities, (collectively "SFAS No. 133"). These statements require that derivatives be recorded on the balance sheets at fair value. Adoption and application of these statements did not impact our results of operations.

We have a long-term purchased power contract that allows the seller to repurchase specified amounts of power with advance notice (Hydro-Quebec Sellback #3). This contract has been determined to be a derivative under SFAS No. 133. The derivative's estimated fair value was an unrealized loss of $5.3 million at September 30, 2005 and $5.7 million at December 31, 2004. The estimated fair value of this derivative is valued using a binomial tree model, and quoted market data when available along with appropriate valuation methodologies.

We have a long-term forward sale contract for the sale of about 15 MW per hour, or a total of 522,544 beginning November 17, 2004 through December 31, 2008. This contract has been determined to be a derivative under SFAS No. 133. We utilize over-the-counter quotations or broker quotes at the end of the reporting period for determining the fair value of this contract. The derivative's estimated fair value was an unrealized loss of $15.2 million at September 30, 2005 and a $0.4 million unrealized gain at December 31, 2004.

The fair value of these derivatives at September 30, 2005 reflects the combination of rising spot and futures prices for natural gas and oil due to increased global demand and production and refining cutbacks resulting from the 2005 hurricane season which are now reflected in the current and projected price of electric energy, especially in New England.

Based on a PSB-approved Accounting Order, we record the change in fair value of these derivatives as deferred charges or deferred credits on the balance sheet, depending on whether the fair value is an unrealized loss or gain.

Catamount: On July 12, 2005, a wholly-owned subsidiary of Catamount entered into a fixed interest rate swap agreement to hedge the variable interest rate debt under the financing agreement described in Note 6 - Long-Term Debt and Sinking Fund Requirements. The swap is for 75 percent of the borrowing amount, or $10.8 million, with a 4.5 percent fixed rate. Other terms of the swap such as variable interest rate pricing, quarterly interest rate reset, quarterly interest payment schedule and December 31, 2013 maturity date are the same as those under the financing agreement. The swap agreement has not been designated as a hedging instrument and the changes in the fair value will be recorded on the Consolidated Statement of Income. The fair value is less than $0.1 million at September 30, 2005.

Reserve for Loss on Power Contract In accordance with the requirements of SFAS No. 5, Accounting for Contingencies, ("SFAS No. 5") in the first quarter of 2004, we recorded a $14.4 million pre-tax loss accrual related to termination of our long-term power contract with Connecticut Valley. The contract was terminated in the first quarter of 2004, as a condition of the Connecticut Valley sale described in Discontinued Operations below. The loss accrual represented Management's best estimate of the difference between expected future sales revenue, in the wholesale market, for the purchased power that was formerly sold to Connecticut Valley and the cost of purchased power obligations. The estimated life of the power contracts that were in place to supply power to Connecticut Valley extends through 2015.

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

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

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Consolidated Summary:
Third quarter 2005 earnings were $2.7 million, or 21 cents per diluted share of common stock, compared to third quarter 2004 earnings of $6.1 million, or 47 cents per diluted share of common stock. For the first nine months of 2005, the Company recorded earnings of $0.2 million, or a 1 cent loss per diluted share of common stock, compared to first nine months 2004 earnings of $19.9 million, or $1.56 per diluted share of common stock. The tables below provide a reconciliation of diluted earnings (loss) for periods reported.

Third quarter 2005 versus third quarter 2004:

2004 Earnings per diluted share

$.47

Year-over-Year Effects on Earnings:
   Higher retail revenue
   Higher resale sales
   Higher purchased power costs
   Catamount - loss in 2005 versus earnings in 2004
   Other
      Subtotal

2005 Earnings per diluted share

.09
.04
(.19)
(.14)
(.06)

(.26)

$.21

First nine months 2005 versus first nine months 2004:

2004 Earnings per diluted share

$1.56

Year-over-Year Effects on Earnings:
   Higher resale sales
   Higher retail revenue (a)
   Regulatory asset amortizations
   Higher equity in earnings of utility affiliates
   Catamount - loss in 2005 versus earnings in 2004
   Higher purchased power costs (a) (b)
   Higher transmission and distribution costs
   IRS tax settlement received in 2004
   Higher administrative and general costs
   Other
      subtotal

Net impact of March 29, 2005 Rate Order recorded in the first quarter of 2005

Net impact of Connecticut Valley sale recorded in 2004:
   Gain on discontinued operations
   SFAS No. 5 loss accrual - termination of power contract
     subtotal

2005 Loss per diluted share

(a) excludes effect of first quarter 2005 Rate Order charge which is included in 'Net      impact of March 29, 2005 Rate Order recorded in the first quarter of 2005' above
(b) excludes first quarter 2004 SFAS No. 5 loss accrual, which is listed separately in      'Net impact of Connecticut Valley sale recorded in 2004' above

.28
.09
.07
.04
(.23)
(.19)
(.11)
(.09)
(.08)
(.12)

(1.01)
.69

(.34)

(.91)

(.32)

$(0.01)

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

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Operating Revenues The majority of our operating revenues are generated through retail sales from the regulated Vermont utility business. Other resale sales are related to the sale of excess power from our owned and purchased power supply portfolio. Operating revenues and related mWh sales for the three and nine months ended September 30, 2005 and 2004 are summarized below:

	Three Months Ended September 30				Nine Months Ended September 30
	mWh Sales		Revenues (000's)		mWh Sales		Revenues (000's)
	2005	2004	2005	2004	2005	2004	2005	2004
Retail sales: Residential Commercial Industrial Other retail Total retail sales Resale sales: Firm (1) Other Total resale sales Retail customer refund Other revenues Total	240,818 240,678 99,448 1,354 582,298 1,020 101,584 102,604 - - 684,902	220,046 223,078 100,588 1,366 545,078 994 136,944 137,938 - - 683,016	$31,394 27,405 7,634 394 66,827 62 6,560 6,622 3 1,561 $75,013	$29,780 26,902 7,946 407 65,035 47 5,701 5,748 - 1,957 $72,740	731,807 668,576 305,154 4,029 1,709,566 3,455 437,432 440,887 - - 2,150,453	711,303 639,071 307,986 4,075 1,662,435 3,371 414,692 418,063 - - 2,080,498	$95,378 78,296 24,848 1,179 199,701 176 26,106 26,282 (6,194) 5,961 $225,750	$94,093 77,057 25,331 1,208 197,689 210 20,347 20,557 - 6,243 $224,489

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

Three Months Ended
September 30,
2005 vs. 2004

Nine Months Ended
September 30,
2005 vs. 2004

Retail revenues:
   Volume (mWh)
   Average price due to customer sales mix
   Average price due to rate reduction
   Subtotal
Firm resale sales
Other resale sales
Retail customer refund
Other revenues
Increase (decrease) in Operating revenues

$4,775
(1,112)
  (1,871)
1,792
15
859
3
     (396)
$2,273

$6,024
(611)
(3,401)
2,012
(34)
5,759
(6,194)
     (282)
$1,261

Operating revenues increased $2.3 million in the third quarter of 2005 compared to the same period in 2004, due to the following factors:

Retail sales increased $1.8 million due to a 6.8 percent increase in sales volume, partially offset by the 2.75 percent rate reduction beginning in April 2005 and lower average unit prices due to customer sales mix. During the period, residential and commercial customer usage increased primarily due to warmer weather in 2005, while industrial customer usage decreased slightly. In total, the increased sales volume contributed about $4.8 million to the favorable variance, while the rate reduction decreased revenue by $1.9 million and lower average unit prices decreased revenue by $1.1 million.
Resale sales increased $0.9 million due to higher average prices, partially offset by fewer mWh available for resale due to increased retail sales. The higher average price reflects an overall increase in wholesale power market prices in New England. In total, higher average prices contributed $2.3 million to the favorable variance, while lower volume decreased resale sales revenue by $1.4 million.
Other operating revenue decreased $0.4 million mostly related to higher revenue in 2004 from mutual aid work in Florida and increased reserves in 2005 due to negotiations related to a pole attachment tariff settlement. These unfavorable items were partly offset by higher transmission revenue and third-party billings including mutual aid work in Massachusetts and maintenance work for the Vermont Yankee plant outage in the third quarter of 2005.

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Operating revenues increased $1.3 million for the first nine months of 2005 compared to the same period in 2004 due to the following factors:

The retail customer refund reduced revenue by $6.2 million. The Rate Order required a refund to customers for over-collections during the period April 7, 2004 through March 31, 2005. Of the $6.2 million, $1.7 million is attributed to 2005 and $4.5 million is attributed to 2004. See Retail Rates above for additional information.
Retail sales increased $2.0 million primarily due to a 2.8 percent increase in sales volume, partially offset by the 2.75 percent rate reduction beginning in April 2005 and lower average unit prices due to customer sales mix. Residential and commercial customer usage increased primarily due to warmer summer weather in 2005, while industrial customer usage decreased slightly. In total, the increased sales volume contributed about $6.0 million to the favorable variance, while the rate reduction decreased revenue by about $3.4 million and lower average unit prices decreased revenue by $0.6 million.
Resale sales increased $5.8 million primarily due to higher average market rates and more mWh available for resale in 2005 compared to the same period in 2004. In 2005, CV sold most of its excess power supply through two forward sale contracts and the remainder to ISO-New England. In 2004, CV sold its excess power supply to ISO-New England and other third parties, but there were fewer mWh available for resale due to second quarter 2004 nuclear plant outages. In total, higher average prices contributed $4.2 million to the favorable variance, increased resale sales volume contributed $1.1 million, and higher capacity-related revenues contributed about $0.5 million.
Other operating revenue decreased $0.3 million mostly related higher revenue in 2004 due to mutual aid work in Florida and increased reserves in 2005 due to negotiations related to a pole attachment tariff settlement. These unfavorable items were partly offset by higher transmission revenue and third-party billings including mutual aid work in Massachusetts.

Purchased Power Most of our power purchases are made under long-term contracts. These contracts and other power supply matters are discussed in more detail in Power Supply and Transmission Matters below. The primary components of purchased power expense are as follows (in thousands):

	Three Months Ended September 30, 2005 2004		Nine Months Ended September 30, 2005 2004
VYNPC* (a) Hydro-Quebec Independent Power Producers (b) subtotal long-term contracts Short-term purchases Miscellaneous purchases SFAS No. 5 loss accrual (net of amortizations) Nuclear decommissioning costs* (b) (c) March 29, 2005 Rate Order Other (d) Total purchased power	$14,398 14,165 3,009 31,572 7,065 8 (299) 1,372 - (79) $39,639	$15,425 14,133 4,249 33,807 1,744 23 (299) 516 - (164) $35,627	$44,955 43,062 13,035 101,052 13,700 45 (897) 3,567 2,441 43 $119,951	$41,626 42,583 15,646 99,855 14,287 60 13,454 1,644 - (1,386) $127,914
* Purchased power transactions with affiliates. Amounts shown in the table above include regulatory amortizations and deferrals described in (a) and (c) that are not included in monthly billings from affiliates. Also see Note 2 - Investments in Affiliates. (a) For the nine months ended September 30, 2005 excludes a $1.1 million tax credit related to our share of an IRS settlement received by VYNPC that we recorded as a regulatory liability. Also excludes nuclear insurance settlements that we deferred per PSB approval. See Power Supply and Transmission Matters below. (b) For nine months ended September 30, 2005, excludes first quarter 2005 Rate Order adjustments shown separately in the table. See Retail Rates above for additional information. (c) Includes deferral of Yankee Atomic incremental dismantling costs prior to April 1, 2005 when they were eliminated in accordance with the Rate Order. (d) Includes amortization and (deferrals) of incremental nuclear refueling outage costs related to Millstone Unit #3 and deferrals related to the Vermont Yankee uprate described in Power Supply and Transmission Matters below. For the nine months ended September 30, 2004, also includes deferral of incremental replacement energy costs related to the 19-day unscheduled Vermont Yankee plant outage. For year-over year comparison purposes these items are included in the variance explanation for short-term purchases.

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The related mWh purchases from these sources are summarized below:

	Three Months Ended September 30,			Nine Months Ended September 30,
	2005	2004	More (Less)	2005	2004	More (Less)
VYNPC Hydro-Quebec Independent Power Producers Short-term purchases Miscellaneous purchases Total mWh	361,905 193,119 27,071 56,903 502 639,500	353,955 194,219 40,067 29,796 1,406 619,443	7,950 (1,100) (12,996) 27,107 (904) 20,057	1,124,906 604,556 107,383 115,267 2,431 1,954,543	951,554 589,360 135,524 213,111 3,111 1,892,660	173,352 15,196 (28,141) (97,844) (680) 61,883

Purchased power expense increased $4.0 million for the third quarter of 2005 compared to the same period in 2004 due to the following factors:

Long-term purchases decreased $2.2 million due to lower-priced energy under the Company's purchased power contract ("PPA") with Vermont Yankee Nuclear Power Corporation ("VYNPC"), and lower output from Independent Power Producers. VYNPC purchases contributed $1.0 million ($1.4 million due to lower PPA prices, offset by $0.4 million due to more purchases), and lower output from Independent Power Producers contributed $1.2 million.
Short-term purchases increased $5.4 million due to higher average prices and more purchases during the period. The combination of higher retail sales and lower output from our hydro facilities and Independent Power Producers resulted in more short-term purchases to serve retail sales. The higher average prices reflect an overall increase in market prices in New England.
Nuclear decommissioning costs increased $0.8 million related to higher Connecticut Yankee rates under FERC-approved tariffs and elimination of accounting deferrals for incremental Yankee Atomic dismantling costs per the Rate Order.

Purchased power expense decreased $8.0 million in the first nine months of 2005 compared to the same period in 2004 due to the following factors:

In the first quarter of 2004, in accordance with Statement of Financial Accounting Standards ("SFAS") No. 5, Accounting for Contingencies ("SFAS No. 5"), we recorded a $14.4 million pre-tax loss accrual due to termination of the long-term power contract with Connecticut Valley. The loss accrual represented management's best estimate of the difference between expected future sales revenue, in the wholesale market, for the purchased power that was formerly sold to Connecticut Valley and the cost of that power. The loss accrual is being reversed and amortized against power expense on a straight-line basis through 2015, the estimated life of the power contracts that were in place to source the Connecticut Valley power contract.
Long-term purchases increased $1.2 million primarily due to more energy purchases from VYNPC, offset by lower output from Independent Power Producers. The increase in VYNPC purchases primarily resulted from scheduled and unscheduled Vermont Yankee plant outages in 2004 with no comparable plant outages in 2005. In total, VYNPC purchases contributed $3.3 million to the increase, including $7.4 million due to higher volume, offset by $4.1 million due to lower-priced energy under the PPA. Other factors contributing to the increase in long-term purchases included $0.5 million due to more deliveries under the Hydro-Quebec contract, offset by $2.6 million due to lower output from Independent Power Producers.
Short-term purchases increased $0.8 million primarily due to higher average market prices for a higher volume of spot market purchases in 2005, offset by fewer replacement energy purchases related to nuclear plant outages in 2004. In 2005 short-term purchases were made through ISO-New England compared to 2004 when replacement energy purchases were made with third parties at lower average prices. The higher average market prices paid in 2005 includes increased operating reserve, congestion and marginal loss charges.
Accounting entries related to the first-quarter 2005 Rate Order charge, described in Retail Rates above, increased purchased power expense by about $2.5 million mostly related to Yankee Atomic incremental dismantling costs and Vermont Yankee replacement energy costs related to a 2004 unscheduled outage.
Nuclear decommissioning costs increased $1.9 million, including $1.1 million due to higher Connecticut Yankee rates under FERC-approved tariffs and $0.9 million due to elimination of deferrals for incremental Yankee Atomic dismantling costs that were eliminated per the Rate Order.

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Operating Expenses Operating expenses represent costs incurred to support our core business. The variances in income statement line items for Operating Expenses on the Condensed Consolidated Statements of Income for the third quarter and nine months of 2005 versus the same periods in 2004 are shown in the table below (in thousands). First quarter 2005 effects of the Rate Order are shown separately.

	2005 over / (under) 2004
	Three Months Ended September 30		Nine Months Ended September 30

	Total Variance	Percent	Related to Operations	Related to Rate Order	Total Variance	Percent
Operation Purchased power (explained above) Production and transmission Other operation Maintenance Depreciation Other taxes, principally property Taxes on income Total operating expenses	$4,012 683 (1,144) 514 127 96 (221) $4,067	11.3% 11.3 (10.5) 11.9 3.2 2.8 (8.3) 6.1%	$(10,404) 1,499 272 983 210 249 7,638 $447	$2,441 - 10,739 - - - (10,022) $3,158	$(7,963) 1,499 11,011 983 210 249 (2,384) $3,605	(6.2)% 8.0 33.5 8.1 1.7 2.5 (167.0) 1.7 %

Production and transmission: These expenses are associated with generating electricity from our wholly and jointly owned units, and transmission of electricity. The increase in 2005 is primarily related to higher ISO-New England transmission costs due to higher rates under the NEPOOL open access transmission tariff, higher production fuel costs related to higher oil and wood unit prices, higher VELCO demand-based charges, and other costs, partially offset by lower Hydro-Quebec Phase I and Phase II support charges and our share of Highgate savings.

Other operation: These expenses are related to operating activity such as regulatory deferrals and amortizations, customer accounting, customer service, administrative and general and other operating costs incurred to support our core business.

The $10.7 million related to the Rate Order primarily resulted from the calculation of overearnings for 2001 - 2003 as described in Retail Rates above. The nine months of 2004 includes the favorable impact of an insurance settlement received in the second quarter of 2004. The remaining increase resulted from higher pension, employee medical costs, bondholder consent fees, higher officers and directors' insurance premiums and various costs, offset by lower employee-related costs such as retiree medical costs and worker's compensation claims, consulting expenses in 2004 related to an IRS tax settlement, a second quarter 2004 customer bankruptcy and lower bad debt expense 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. The increase is primarily related to higher contractor costs for an annual maintenance outage at McNeil, one of our jointly owned generating units. Other factors include higher environmental expenses related to a transformer outage.

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. See Income Tax Matters below for additional information.

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


	Total Variance	Percent	Related to Operations	Related to Rate Order	Total Variance	Percent
Equity in earnings of affiliates Equity in earnings of non-utility investments Allowance for equity funds during construction Gain on sale of non-utility investments Other income Other deductions Benefit for income taxes Total other income and deductions	$75 (1,118) (28) (1,980) 237 269 1,066 $(1,479)	18.3% (97.6) (59.6) (100.0) 19.1 14.8 202.3 (60.0)%	$565 (2,361) (44) (1,980) (134) (1,675) 1,621 $(4,008)	- - - $(822) (403) 598 $(627)	$565 (2,361) (44) (1,980) (956) (2,078) 2,219 $(4,635)	64.1 % (63.0) (46.3) (100.0) (16.8) (41.0) 129.6 (82.6)%

Equity in earnings of affiliates: These are related to our equity investments, VELCO and VYNPC. The increase is mostly related to our share of higher VELCO earnings associated with the $7.0 million additional equity investment that we made in the fourth quarter of 2004.

Equity in earnings of non-utility investments: These are related to Catamount's equity investments in non-regulated independent power projects. The decrease is primarily due to Catamount's investment in Appomattox, for which the project lease expired in November 2004 and equity losses from certain equity investments.

Other income: These income items include interest and dividend income, interest on temporary investments and non-utility notes receivable, Catamount's operating revenue, regulatory asset carrying costs, amortization of contributions in aid of construction and various miscellaneous other income items.

The decrease is related to recognition of a $0.9 million fee associated with Catamount's United Kingdom development efforts in 2004, offset by a $1.0 million contingent-based fee received in 2005 related to Catamount's sale of the Fibrothetford note receivable in 2004. A favorable IRS tax settlement was received in 2004, partially offset by lower regulatory carrying charges in 2005 related to the Rate Order. The $0.8 million decrease related to the Rate Order reflects required adjustments to carrying charges for deferred Vermont Yankee sale costs and Vermont Yankee fuel rod costs as described in Retail Rates above. Also, interest income was higher due to collateral requirements associated with our power purchase and sale transactions.

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

The $0.4 million increase related to the Rate Order reflects disallowance of a portion of Vermont Yankee fuel rod costs as described in Retail Rates above. The nine months also includes impairment and realized losses associated with certain available-for-sale debt securities that we no longer intended to hold to maturity. Other miscellaneous items include higher insurance expense due to death benefit proceeds received in 2004, partially offset by favorable market performance 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. See Income Tax Matters below for additional information.

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Interest Expense Interest expense includes interest on long-term debt, dividends associated with mandatory redeemable preferred stock and other interest of the utility business and our unregulated businesses. The variances in income statement line items for Interest Expense on the Condensed Consolidated Statements of Income for the third quarter and nine months of 2005 versus 2004 are shown in the table below (in thousands). First quarter 2005 effects of the Rate Order are shown separately.

	2005 over / (under) 2004
	Three Months Ended September 30		Nine Months Ended September 30

	Total Variance	Percent	Related to Operations	Related to Rate Order	Total Variance	Percent
Interest on long-term debt Other interest Allowance for borrowed funds during construction Total interest expense * variance exceeds 100 percent	$29 22 12 $63	1.4 % 13.4 (66.7) 2.9 %	$(1,279) 491 22 $(766)	- $1,168 - $1,168	$(1,279) 1,659 22 $402	18.1 % * (57.9) 5.6%

Interest on long-term debt: The decrease primarily resulted from lower interest rates due to the August 2004 bond refinancing, partially offset by Catamount's higher interest expense associated with a financing agreement obtained in July 2005 for Catamount's Sweetwater investments.

Other interest expense: The $0.5 million increase for the nine months is related to a favorable IRS tax settlement in 2004, partially offset by dividends on mandatorily redeemable preferred stock described below. The $1.2 million Rate Order increase is primarily related to carrying costs associated with the recalculation of overearnings for 2001 - 2003 as described in Retail Rates above.

Discontinued Operations On January 1, 2004, Connecticut Valley completed the sale of substantially all of its plant assets and its franchise to Public Service Company of New Hampshire ("PSNH"). See discussion of Discontinued Operations below.

Dividends on preferred stock Preferred stock dividends decreased by $0.2 million in the third quarter and $0.5 million in the nine months of 2005 primarily related to SFAS 150, Accounting for Certain Financial Instruments with the Characteristics of Both Liabilities and Equity ("SFAS No. 150"). This statement established standards for classifying and measuring as liabilities certain financial instruments that embody obligations of the issuer and have characteristics of both liabilities and equity. We implemented the income statement impacts of SFAS No. 150 in the fourth quarter of 2004.

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

Power Contract Commitments
Hydro-Quebec We purchase a significant part of our power from Hydro-Quebec under the Vermont Joint Owners ("VJO") Power Contract and related contracts negotiated between us and Hydro-Quebec, which extend through 2016. There are specific contractual provisions that provide that in the event any VJO member fails to meet its obligation under the contract with Hydro-Quebec, the remaining VJO participants, including us, must "step-up" to the defaulting party's share on a pro rata basis.

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

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VYNPC We have a 35 percent entitlement in Vermont Yankee plant output sold by Entergy Nuclear Vermont Yankee, LLC ("ENVY") to VYNPC, through a long-term power purchase contract ("PPA") with VYNPC. One remaining secondary purchaser continues to receive a small percentage of our entitlement, reducing our entitlement to about 34.83 percent. ENVY has no obligation to supply energy to VYNPC over the amount the plant is producing, so entitlement holders receive reduced amounts when the plant is operating at a reduced level, and no energy when the plant is not operating. Vermont Yankee's scheduled refueling outage began on October 22, 2005 and was originally expected to be off-line until November 20, 2005. Recently, ENVY determined that the plant may begin production again on November 10, 2005 followed by a three day ramp up to full power. Based on the shorter outage period, incremental replacement power costs during the outage are expected to be about $4.7 million above amounts currently recovered in retail rates. This high level of expected replacement power cost resulted from very high wholesale power market prices driven primarily by the extraordinary effects of hurricanes Katrina and Rita on the price of natural gas.

Prior to the outage, we purchased forward supplies of power at a fixed price of about $115 per mWh to minimize exposure to day ahead and real time spot market power price volatility. The ultimate incremental cost of replacement power during the outage will be determined when actual information is available including: 1) length of the outage and output during ramping; 2) balance of hourly loads; 3) hourly supplies; and 4) hourly prices. We may seek an Accounting Order for deferral of the incremental replacement power costs for recovery at our next rate proceeding. If the outage was unexpectedly and significantly extended (beyond 45 days), we may seek PSB approval of a surcharge on current retail rates that could be applied to customer bills six days after public notification.

In the third quarters of 2005 and 2004, VYNPC's power billings to us included our share of distributions from Nuclear Electric Insurance Limited ("NEIL") and similar insurance providers. Pursuant to PSB approval of the Vermont Yankee sale, the credits must benefit ratepayers through programs to promote renewable resources. As such, these items are recorded as regulatory liabilities. Additionally, we received a $1.1 million credit or reduction in our June 2005 power billing from VYNPC, representing our share of the settlement of a tax dispute payment received by VYNPC from the IRS. We recorded the credit (less a small portion related to wholesale) as a regulatory liability. We are currently evaluating alternatives for use of these funds.

In March 2004, the PSB approved ENVY's request to increase generation at the Vermont Yankee plant by 110 megawatts. The PSB's approval included conditions, including that ENVY provide outage protection indemnification ("Ratepayer Protection Proposal" or "RPP") for times the uprate causes reductions in output that reduce our value of the PPA. Our maximum right to indemnification under the RPP is about $2.8 million for the three-year period beginning in May 2004 and ending after completion of the uprate (or a maximum of three years). Our purchases from VYNPC will not be affected by increased generation resulting from the uprate as our entitlement percentage of plant output would decrease to about 29 percent to match the volume of power we received before the uprate.

Since April 2004, our entitlement has been reduced by an average of about 4 MW due to uprate-related work performed during the plant's 2004 scheduled refueling outage. This reduction is expected to continue until ENVY receives NRC approval for the uprate. The financial effect of this reduction is covered under the terms of the RPP and amounts to about $0.2 million for the first nine months of 2005.

We are seeking recovery from ENVY, under the RPP, for incremental replacement energy costs that we incurred when the plant was shut down from June 18 to July 7, 2004. We believe the plant went off line due to problems associated with uprate-related improvements made by ENVY, and have sought about $0.8 million from ENVY. ENVY contends that the problem would have occurred regardless of the uprate. Having failed to reach a settlement with ENVY, we petitioned the PSB for resolution. We, Green Mountain Power and ENVY are currently in discussions to settle the matter.

In the second quarter of 2004, based on the PSB's preliminary approval of our request for an Accounting Order, we deferred about $0.8 million for incremental replacement energy costs incurred as a result of the 2004 plant outage. In the first quarter of 2005, these deferred costs were reduced to zero pursuant to the Rate Order, resulting in a $0.8 million pre-tax charge to purchased power expense. The Rate Order also requires that we record any partial or full reimbursement received by ENVY under the RPP as a regulatory liability for return to ratepayers in our next rate proceeding.

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In April 2004, ENVY reported that two short spent fuel rod segments were not in what ENVY believed to be their documented location in the spent fuel pool. Subsequently, ENVY's continuing documentation review led to the discovery of the fuel rod segments in a container in the spent fuel pool. During that time, ENVY notified VYNPC that based on the terms of the Purchase and Sale Agreement dated August 1, 2001, and facts at the time, it was their view that costs associated with the spent fuel rod segment inspection effort were the responsibility of VYNPC. VYNPC responded that based on information at the time there was no basis for ENVY's claim. VYNPC was not fined by the NRC as a result of the lost fuel rods. While this matter has not been fully resolved, we do not believe that we have any potential liability related to the lost fuel rods.

ENVY has announced that, under current operating parameters, it will exhaust the capacity of its nuclear waste (spent fuel) storage pool in 2007 or 2008 and will need to store nuclear waste in so-called 'dry cask storage' facilities to be constructed on the site. Construction and use of such dry cask storage facilities requires approval from the Vermont State Legislature, in addition to PSB approval. In early June 2005, the Vermont State Legislature passed a law authorizing ENVY to construct and use dry cask storage facilities on the site through its current license. In late June 2005, ENVY filed an application with the PSB for permission to install dry cask storage facilities at the site. In September 2005, ENVY filed notice with the NRC that it intended to seek a license extension for the Vermont Yankee plant. The notice said the plant would seek a 20-year extension, which if approved would allow the plant to operate until 2032.

If ENVY is unsuccessful in receiving regulatory approval for dry cask storage, ENVY has announced that it could be required to shut down the Vermont Yankee plant in 2007 or 2008, instead of its current license life of 2012. If the Vermont Yankee plant is shut down, we would lose about 50 percent of our committed energy supply and would have to acquire replacement power resources comprising about 40 percent of our estimated power supply needs. Based on projected market prices, the value of the lost output is estimated to be about $50 million on an annual basis. Based on this estimate, we would require a retail rate increase of about 18 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.

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

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

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

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

In the second quarter of 2005, FERC issued an initial decision on ISO-New England's proposal for a new system of payments to generators that New England's state regulators fear will increase future power costs to the region's load serving entities and thus consumers. Since we expect to have adequate capacity to serve our load through 2012 we do not expect that, if implemented, this mechanism would materially increase our costs for at least the next six years. We are not able to determine whether or not any such new mechanism will ultimately increase cost for consumers due to unknown future dynamics of a number of market factors.

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The new pricing mechanism, referred to as 'locational installed capacity' ("LICAP") would replace an existing mechanism that determines charges for the installed generating capacity requirement imposed on load servers. The new mechanism is intended to encourage generators to stay in business and to construct new generators in parts of the region that are short on the capacity to produce power.

Recently, FERC responded to the concerns of the region's state regulators and postponed implementation so that additional alternatives may be considered via a 90-day alternative dispute resolution settlement process. Implementation is not expected in any form before October 2006 and will most likely involve a multi-year approach. We are not able to determine the impact of this charge at this time.

Transmission-related matters We operate our transmission system under an open-access tariff, pursuant to FERC Order No. 888. On March 24, 2004, FERC conditionally approved the filing made by ISO-New England and the New England transmission owners to create a Regional Transmission Organization ("RTO") for New England. The RTO parties submitted a compliance filing to FERC in December 2004, and the RTO began operating on February 1, 2005.

Under the RTO, Highgate and related facilities, owned by a number of Vermont utilities and VELCO, are classified as Highgate Transmission Facility ("HTF") with a five-year phase-in of Regional Network Service ("RNS") reimbursement treatment. At the end of the phase-in period, our net cost for Highgate will be based on our NEPOOL load ratio (about 2 percent) rather than our 46 percent ownership share of the facilities. Our share of savings related to the Highgate facilities are now expected to be about $0.5 million in 2005, $1.0 million in 2006, $1.4 million in 2007, $1.8 million in 2008 and $2.2 million in 2009. As of September 30, 2005, we have received about $0.3 million of Highgate-related savings.

Currently, about one-third of the cost of New England's existing and new high-voltage transmission system (115 kV looped facilities), Pool Transmission Facility ("PTF"), is shared by all New England utilities, and by 2008 all of the PTF costs will be shared. At this time we are not able to predict the impact of other transmission costs related to the RTO. Apart from the new RTO, we expect other transmission costs will increase due to growth in new transmission facilities in New England. However, better reliability and economic power transfers elsewhere in the region benefits Vermont's reliability because of the highly integrated nature of New England's high-voltage network.

At this time, VELCO is planning several significant upgrades, portions of which have been approved by NEPOOL for shared cost treatment in New England-wide rates for transmission services, including the so-called Northwest Reliability Project ("NRP"). The estimated cost of the NRP is now about $198 million, a $78 million increase from the original estimate that was completed in early 2003. Additional final compliance approvals will be required on the detailed components of the NRP, but the PSB has allowed VELCO to start construction on the initial stages of the project. Citing the cost increase, certain interveners asked the PSB to reopen the proceeding in which VELCO received the overall Certificate of Public Good for the NRP. The PSB declined to reopen the proceeding. An appeal of the PSB's decision has been filed with the Vermont Supreme Court by certain interveners.

The RTO cost-sharing approach will limit our costs related to Vermont transmission upgrades but we will pay a share of projects undertaken to support region-wide reliability elsewhere in New England. The net economic effect on us is expected to be beneficial, as the sharing approach provides cost and reliability benefits in providing service to our customers, because our load share is a small fraction of New England's load, and the facilities upgrades VELCO is planning improve the reliability and efficiency of the transmission network. Certain future transmission facilities will not qualify for cost sharing, and those costs will be charged locally rather than regionally; our share of such costs will be affected by FERC-approved cost-allocation process contained in VELCO's and our tariffs and agreements.

In addition to the NRP, VELCO is working with us on a project to solve load serving and reliability issues related to a 46-kV transmission line extending from Bennington to Brattleboro, Vermont, which we refer to as the Southern Loop. It serves about 25 percent of our load. We are evaluating alternatives to resolve the Southern Loop issues, including significant upgrades to the transmission system. Such upgrades would provide both regional and local reliability benefits and some of the upgrades could be eligible for cost sharing on a New England-wide basis under the current regional tariff. The estimated cost of these transmission system upgrades ranges from $43 to $60 million with construction likely to occur in 2007 or 2008. In October 2005, we initiated a public involvement process to gain input on how best to improve and ensure reliable electric service in Southern Vermont.

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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 73.6 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 will receive a water quality certificate from the State, which is needed for FERC to relicense the facilities for 30 years. The agreement also stipulates that subject to various conditions, we must begin decommissioning Peterson Dam in about 20 years. The agreement requires PSB approval of full rate recovery related to decommissioning the Peterson Dam, including recovery of replacement power costs when the dam is out of service. In July 2003, the VANR published its draft water quality certificate. In October 2003, pursuant to the schedule set forth in the agreement, we filed a petition with the PSB for approval of the rate recovery mechanisms, and the case has continued to progress through the regulatory process.

In June 2005, FERC issued a 30-year license for the four dams including Peterson Dam. While FERC determined that the VANR waived its rights to issue a water quality certificate, the license includes conditions, previously agreed upon by us, the DPS, VANR and other parties, relating to project operations, fish and wildlife, recreation, land use, and historic properties. The license does not include conditions relating to decommissioning of Peterson Dam in 20 years, or cost recovery. These issues are under review by the PSB, with hearings scheduled for later this year. We cannot predict the outcome of this matter 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. All three of these nuclear plants have been shut down and are undergoing decommissioning. We also have a joint-ownership interest in Millstone Unit #3. Our obligations related to these plants are described below.

Maine Yankee, Connecticut Yankee and Yankee Atomic
All three companies collect decommissioning and closure costs through 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. Based on the regulatory process, we believe our share of decommissioning and closure costs for each plant will continue to be recovered through the regulatory process. Although we believe that these costs will ultimately be recovered from customers, there is a risk that FERC may not allow full recovery of Connecticut Yankee's increased costs in wholesale rates, as described below.

Our share of Maine Yankee, Connecticut Yankee and Yankee Atomic estimated costs are reflected on the Condensed Consolidated Balance Sheet as regulatory assets and nuclear decommissioning liabilities (current and non-current). These amounts are adjusted when revised estimates are provided by the companies. At September 30, 2005, we had regulatory assets of about $5.0 million related to Maine Yankee, $10.9 million related to Connecticut Yankee and $3.5 million related to Yankee Atomic. The regulatory asset balance related to Yankee Atomic also includes about $0.8 million for incremental decommissioning costs that we have paid and are now recovering in retail rates pursuant to the Rate Order. These estimated costs are being collected from customers through existing retail rate tariffs. Also see Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits, regarding the impacts of the Rate Order.

Maine Yankee, Connecticut Yankee and Yankee Atomic are seeking recovery of fuel storage-related costs stemming from the default of the United States Department of Energy ("DOE") under the 1983 fuel disposal contracts that were mandated by the United States Congress under the High Level Waste Act. All three are parties to a lawsuit against the DOE seeking damages based on the DOE's default. Maine Yankee's damage claim is about $160 million, Connecticut Yankee's damage claim is about $197 million and Yankee Atomic's damage claim is about $191 million. None of the plants has included any allowance for potential recovery of these claims in their FERC-filed cost estimates.

The trial on determination of damages began on July 12 and ended August 31, 2004. Closing arguments were held in January 2005 and final post-trial briefs were filed in February 2005. The Department of Justice submitted a motion to the court during the damage trial arguing that the spent fuel obligations prior to April 1983 should be treated as an offset to any award of damages. The Court's ruling on that matter is expected to be issued with its overall ruling in the case, which is expected by the end of 2005.

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Maine Yankee: We have a 2 percent ownership interest in Maine Yankee. Beginning November 1, 2004, Maine Yankee's billings to sponsor companies have been based on its September 16, 2004 FERC-approved settlement, which provides for recovery of Maine Yankee's forecasted costs of providing service through a formula rate contained in its power contracts through October 31, 2008 and replenishment of the DOE Spent Fuel Obligation through collections from November 2008 through October 2010. On October 3, 2005, Maine Yankee completed its decommissioning efforts and the Nuclear Regulatory Commission ("NRC") amended its operating license for operation of the Independent Spent Fuel Storage Installation.

In October 2005, Maine Yankee provided an updated forecast for ongoing costs which reflects an estimated increase of about $10.1 million. The increase is primarily related to higher than expected interest expense. Our share of these estimated increased costs is about $0.2 million.

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

Bechtel Litigation: Connecticut Yankee is involved in a contract dispute with Bechtel Power Corporation ("Bechtel"), which resulted in default termination of the decommissioning services contract between Connecticut Yankee and Bechtel effective July 2003. Connecticut Yankee continues to prosecute its counterclaims for excess completion costs and other damages against Bechtel in Connecticut Superior Court ("Court"). Discovery and depositions are nearly complete in support of a trial scheduled to begin in May 2006.

In the prejudgment remedy proceeding before the Court, Bechtel sought garnishment of the decommissioning trust and related payments. In October 2004, Bechtel and Connecticut Yankee entered into an agreement in which Bechtel agreed to withdraw its request for garnishment of the decommissioning trust and related payments in return for attachment of all real property owned by Connecticut Yankee in Connecticut up to $7.9 million and the escrowing of $41.7 million the sponsors are scheduled to pay to Connecticut Yankee through June 30, 2007 in respect to Connecticut Yankee's common equity. This agreement is subject to the Court's approval and would not be implemented until the Court found that such assets were subject to attachment. Connecticut Yankee has contested the attachability of such assets. The agreement does not materially change the legal positions in this litigation. The Connecticut Department of Public Utility Control ("CT DPUC"), an intervenor in this proceeding, did not object to the agreement. The Court has taken no further action.

On September 6, 2005, Connecticut Yankee submitted a summary judgment motion for dismissal of Bechtel's negligent misrepresentation claim. On October 7, 2005, Bechtel filed a motion withdrawing its negligent misrepresentation claim.

FERC Rate Case Filing: Connecticut Yankee's estimated decommissioning and plant closure costs for the period 2000 through 2023 ("2003 estimate") have increased by about $395 million compared to the cost estimate in its 2000 FERC rate case settlement. The revised estimate reflects increased costs including the fact that Connecticut Yankee is now directly managing the work (self-performing) to complete decommissioning of the plant following the default termination of Bechtel. On July 1, 2004, Connecticut Yankee filed the 2003 estimate with FERC as part of its rate application ("Filing") seeking additional funding for recovery of these increased costs. 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 CT DPUC and Bechtel have intervened in this rate case.

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

Both the CT DPUC and Bechtel filed testimony in the FERC proceeding claiming that Connecticut Yankee was imprudent in its management of the decommissioning project. In its February 22, 2005 filed testimony, the CT DPUC recommended a disallowance of $225 million to $234 million out of Connecticut Yankee's $395 million requested increase. The Company's share of the CT DPUC's recommended disallowance is between $4.5 million and $4.7 million.

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

Yankee Atomic: We have a 3.5 percent ownership interest in Yankee Atomic. Costs billed by Yankee Atomic are based on an April 4, 2003 FERC filing, in which FERC approved the resumption of billings starting June 2003 for a recovery period through 2010. The decommissioning effort is largely complete. Following decommissioning, the remaining on-site function will be to operate the Independent Spent Fuel Storage Installation.

Yankee Atomic is preparing an application to FERC for increased decommissioning charges to go into effect in early 2006, subject to FERC acceptance and approval. Yankee Atomic has identified increases in the scope of soil remediation and certain other remediation activities to meet environmental standards, beyond the levels assumed in its previously settled FERC rate case. While the evaluation is not complete, Yankee Atomic has determined that the schedule for completion of physical work will need to extend until mid-2006 and the costs of completing decommissioning will be about $63 million greater than previous estimates. The timing and amount of the FERC application and the increase in decommissioning charges are under development, but Yankee Atomic expects that it will seek rate recovery of a significant component of the increased expenditures during 2006. Our share of this increase in decommissioning costs amounts to about $2.2 million. We cannot predict the timing and outcome of a FERC proceeding required for collection of the increased Yankee Atomic decommissioning costs, but we believe these incremental costs, above costs currently recovered in retail rates, will be recovered in future retail rate proceedings.

Millstone Unit #3

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

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

The Millstone Unit #3 refueling outage was scheduled to begin on October 1, 2005, but instead began on September 29, 2005 when circulating water pumps tripped due to debris in the intake cooling system. The plant was returned to service on October 27. Based on approved regulatory accounting treatment we defer the cost of incremental replacement energy and incremental maintenance costs of the scheduled refueling outage, and are allowed to amortize those costs through the next scheduled refueling outage which typically spans over an 18-month period. We purchased replacement power through ISO-New England during the outage period. Current estimates related to the outage include about $1.4 million for incremental replacement power costs and $0.5 million for incremental maintenance costs.

DIVERSIFICATION
Catamount As of September 30, 2005, Catamount had interests in six operating independent power projects located in Rumford, Maine; East Ryegate, Vermont; Nolan County, Texas; Thuringen, Germany and Mecklenburg-Vorpommern, Germany.

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Catamount is wholly focused on development, ownership and asset management of wind energy projects. Depending on prices, capital and other requirements, Catamount will entertain offers for the purchase of certain of its wind electric generating assets and any of its remaining non-wind electric generating assets. Additionally, Catamount has been seeking an equity investor to co-invest in Catamount. See Sale of Controlling Interest in Catamount above.

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

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

In 2003, Catamount ceased "greenfield" development in Germany to focus development efforts in the United States and United Kingdom. In September 2005, Catamount sold its German development company, Catamount Development GmbH as described below. Catamount is also working on the sale of its German operating wind projects, but Management cannot predict whether it will ultimately consummate a sale of these operating wind projects.

Catamount Results

Catamount recorded a third-quarter 2005 loss of $0.2 million compared to third-quarter 2004 earnings of $1.4 million. Catamount's third-quarter 2004 earnings were primarily related to a $0.6 million after-tax gain and an additional $0.2 million income tax benefit due to the July 2004 sale of Catamount's investment interests in the Rupert and Glenns Ferry cogeneration facilities, and a $0.6 million after-tax gain and an additional $0.2 million income tax benefit due to the September 2004 sale of its Fibrothetford note receivable. Absent the favorable impacts of the 2004 asset sales, Catamount's 2004 operating activities resulted in a $0.2 million loss, which is comparable to the third-quarter 2005 loss.

Catamount recorded a $0.7 million loss in the first nine months of 2005 compared to earnings of $2.0 million in the first nine months of 2004. The 2005 loss is primarily related to termination of Catamount's interest in the Appomattox project due to expiration of the lease in the fourth quarter of 2004, equity losses from an equity investment, higher operating costs and an investment impairment, offset by lower business development costs, amortization expense and an income tax benefit associated with the sale of its German development company. The 2004 earnings were primarily related to the third quarter 2004 asset sales described above.

Catamount or its wholly owned subsidiaries provide certain management, accounting and other services to certain entities in which Catamount holds an equity interest. The fees are designed to recover actual costs or are agreed upon by other equity investors in these entities. Catamount's revenues (included in Other Income on the Condensed Consolidated Statements of Income) include billings of $0.1 million for the third quarter of 2005 and 2004, respectively and $0.4 million and $0.5 million for the nine months ended September 30, 2005 and 2004, respectively. Information regarding certain of Catamount's investments follows.

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

Sweetwater 3 The construction financing closed on May 9, 2005 and commercial operation is expected in late December 2005 or early January 2006. See Liquidity and Capital Resources above.

Rumford Cogeneration ("Rumford"): For the first and second quarters of 2005, Catamount determined that its equity investment in Rumford was impaired. Catamount prepared several scenarios based on varying electric energy prices and other assumptions which resulted in a range of possible outcomes ranging from no impairment to an impairment of $1.7 million. Management determined that the first and second quarter impairment was temporary based on the fact that the electric energy rate was being negotiated between the affected parties. In the third quarter of 2005, based on revised analysis, Management determined that its investment was no longer impaired.

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DK Burgerwindpark Eckolstadt and DK Windpark Kavelstorf GmbH&Co. KG (collectively "Eurowind") In the first quarter of 2005, Catamount recorded an impairment of less than $0.1 million related to its Eurowind investments. Catamount recorded an additional impairment of $0.2 million in the second quarter of 2005. The impairment reflects Management's best estimate of the current market value of these investments based on a non-binding offer from a third party to purchase the projects.

Catamount Development GmbH Sale: In September 2005 Catamount sold its German development company, Development GmbH, to a third party for about $12,000. In the third quarter of 2005, Catamount recorded a gain on the sale of less than $0.1 million and net income tax benefits of $0.4 million.

Eversant As September 30, 2005, Eversant had a $1.4 million equity investment in The Home Service Store Inc. ("HSS"). HSS has established a network of affiliate contractors who perform home maintenance repair and improvements for its members. Eversant accounts for this investment on the cost basis.

Eversant's wholly owned subsidiary, SmartEnergy Water Heating Services, Inc. ("SEWHS"), engages in the sale or rental of electric water heaters in Vermont and New Hampshire. SEWHS had earnings of $0.1 million for the third quarter and $0.3 million in the first nine months of 2005, compared to $0.1 million for the third quarter and $0.3 million in the first nine months of 2004.

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

For accounting purposes, components of the sale transaction are recorded in both continuing and discontinued operations in the first nine months 2004 Condensed Consolidated Statement of Income. Income from discontinued operations included a gain on disposal of about $21 million pre-tax, or $12.3 million after-tax. In addition to the gain on disposal, the Company recorded a loss on power costs of $14.4 million pre-tax, or $8.4 million after-tax, relating to termination of the power contract with Connecticut Valley. The loss is included in Purchased Power in the 2004 Condensed Consolidated Statement of Income. When the two accounting transactions are combined to assess the total impact of the sale, the result was a gain of $3.9 million recorded in the first quarter of 2004.

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

INCOME TAX MATTERS
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. Pre-tax earnings were reduced significantly during the first nine months of 2005, primarily as a result of the first quarter 2005 Rate Order charge described in Retail Rates above. Other items affecting income tax provisions during the periods are discussed below.

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Catamount Asset Sales: In the third quarter of 2005, Catamount sold its German development company, Development GmbH, and recognized $0.4 million of net tax benefits related to the sale. In the third quarter of 2004, Catamount sold its Glenns Ferry and Rupert investment interests and its Fibrothetford note receivable, and recognized $0.4 million in related net tax benefits.

Discontinued Operations: In the first quarter of 2004, taxes on income included a $5.9 million benefit related to the loss accrual resulting from termination of the power contract with Connecticut Valley as described in Note 10 - Discontinued Operations.

IRS Tax Settlement: In the second quarter of 2004, we received $0.5 million from a federal income tax refund related to an appeal for a refund of an overpayment from a prior audit for the tax years 1982 through 1984.

State Tax Legislation: On June 7, 2004, the State of Vermont enacted legislation that reduced the state income tax rate from 9.75 percent to 8.9 percent effective January 1, 2006, and from 8.9 percent to 8.5 percent effective January 1, 2007. In the second quarter of 2004, related deferred tax assets and liabilities were adjusted to reflect the rate change effective January 1, 2006. This rate change reduced regulatory tax assets by about $1.0 million, and increased state income tax expense by about $0.1 million in the second quarter of 2004.

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

Power Supply Requirements The new law establishes a Sustainably Priced Energy Enterprise Development ("SPEED") Program with a collective requirement of all Vermont retail electricity providers to, in aggregate, supply all of their incremental load growth between January 1, 2005 and January 1, 2012 from new renewable supplies, through 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. Under SPEED the PSB may: 1) offer the contracts secured by a PSB-named statewide entity or entities to utilities on a pro rata basis; 2) establish a process by which utilities may demonstrate that their power supply portfolio is sufficiently renewable so as to relieve them of having to accept a pro-rata share of additional SPEED renewable power; 3) encourage utilities to secure long-term contracts for renewable energy; and 4) encourage utility sponsorship and partnerships in the development of renewable energy projects. The SPEED program begins on January 1, 2007 and could require that we purchase certain amounts of our energy supply requirement from new renewable sources while maintaining existing renewable power resources.

By July 1, 2013, the PSB must determine whether Vermont's retail electricity providers have met the SPEED program's requirements. If the requirements have been met, no other PSB action is required. If not met, the law states that the SPEED program's collective requirement reverts to a utility-specific renewable portfolio standard ("RPS"). Each retail electricity provider would have to supply an amount of energy equal to its total incremental energy growth between January 1, 2005 and January 1, 2012 through the use of electricity generated by new renewable resources, capped at a total of 10 percent of the statewide kWh sales during calendar year 2005. As with the SPEED program, this requirement can be met from new renewable resources, through new Renewable Energy Certificates, or a combination of those credits and resources. If the RPS is imposed, it could require that we purchase certain amounts of our energy supply requirement from new renewable sources while maintaining existing renewable power content. Alternatively, if the utility-specific RPS takes effect, we may choose to pay an as yet undetermined per kWh charge set by the PSB.

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. Prior to the law's passage, only an electric utility could initiate an alternative regulation plan proposal. The PSB may only approve an alternative regulation plan if it finds that the plan will not adversely affect our eligibility for rate-regulated accounting in accordance with GAAP and reasonably preserves the availability of equity and debt capital resources to us on favorable terms and conditions. To date, neither we nor the regulators have sought to implement an alternate form of regulation for our operations.

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Future issues and other matters In August 2005, the Energy Policy Act of 2005 ("the Act") was enacted. The Act includes numerous provisions meant to increase domestic gas and oil supplies, improve energy system reliability, build new nuclear power plants and expand renewable energy sources. The Act also repeals the Public Utility Holding Company Act of 1935, effective February 2006. We are currently evaluating the impact the Act may have on results of operations and financial condition.

RECENT ACCOUNTING PRONOUNCEMENTS
See Note 1 to the accompanying Condensed Consolidated Financial Statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk
We consider our most significant risks to be 1) regulatory risk as it relates to timely and full recovery of costs to serve our customers, and 2) wholesale power market risks given that we rely on two long-term contracts that support about 75 percent of our load requirements. Except as discussed below, there were no material changes from the disclosures in our Annual Report on Form 10-K for the year ended December 31, 2004.

Regulatory The Company currently complies with the provisions of SFAS No. 71 Accounting for the Effects of Certain Types of Regulation,("SFAS No. 71") for its regulated Vermont service territory and FERC-regulated wholesale businesses. If we determine the Company no longer meets the criteria under SFAS No. 71, the accounting impact would be an extraordinary charge to operations of about $34.0 million on a pre-tax basis as of September 30, 2005, assuming no stranded cost recovery would be allowed through a rate mechanism.

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

Forward Sale Contract

Hydro-Quebec Sellback #3

Fair value at January 1, 2005 - unrealized gain (loss)
Change in fair value, including amounts settled
Fair value at September 30, 2005 - unrealized gain (loss)

$385
(15,596)
$(15,211)

$(5,735)
456
$(5,279)

Source

Over-the-counter-quotations

Quoted market data & valuation
methodologies

The fair value of these derivatives at September 30, 2005 reflects the combination of rising spot market and futures prices for natural gas and oil due to increased global demand and production and refining cutbacks resulting from the 2005 hurricane season which are now reflected in the current and projected price of electric energy, especially in New England. A 10 percent increase in projected market prices would increase the forward sale contracts fair value unrealized loss by about $3.7 million, and a 10 percent decrease would decrease the fair value unrealized loss by the same amount.

Per a PSB-approved Accounting Order, changes in fair value of these derivatives are recorded as deferred charges or deferred credits on the Condensed Consolidated Balance Sheets depending on whether the fair value is an unrealized loss or 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 Acting Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the "Exchange Act"), as of the end of the period covered by this interim report on Form 10-Q. Based on this evaluation, our Chief Executive Officer and Acting Chief Financial Officer have concluded that, as of September 30, 2005, our disclosure controls and procedures were effective in timely alerting them to internal information related to the Company (including its consolidated subsidiaries) required to be included in reports filed or submitted by the Company to the Securities and Exchange Commission.

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

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PART II - OTHER INFORMATION
Item 1.		Legal Proceedings.
	The Company is involved in legal and administrative proceedings in the normal course of business and does not currently believe that the ultimate outcome of these proceedings will have a material adverse effect on the financial position or the results of operations of the Company, except as otherwise disclosed herein
Item 6.		Exhibits.
		31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
		31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
		32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
		32.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

Dated November 9, 2005

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

Page 65 of 65

	Three Months Ended September 30, 2005 2004		Nine Months Ended September 30, 2005 2004
Net income Preferred stock dividend Earnings (loss) available for common stock	$2,721 92 $2,629	$6,065 259 $5,806	$184 276 $(92)	$19,919 775 $19,144
Average shares of common stock outstanding - basic Dilutive effect of stock options Dilutive effect of restricted stock Dilutive effect of performance plan shares Average share of common stock outstanding - diluted	12,276,642 83,729 4,892 - 12,365,263	12,138,847 123,555 5,892 28,445 12,296,739	12,251,944 - - - 12,251,944	12,105,248 137,320 5,892 28,445 12,276,905

	Nine Months Ended September 30, 2005 2004
Cash paid during the year for: Interest (net of amounts capitalized) Income taxes (net of refunds)	$5,370 $6,431	$7,956 $14,531

	Three Months Ended September 30, 2005 2004		Nine Months Ended September 30, 2005 2004
Operating revenues Operating income Net income Company's ownership interest: Common stock * Preferred stock Company's equity in net income	$7,248 $2,088 $739 47.02% 48.03% $363	$6,363 $2,121 $779 50.49% 46.62% $308	$22,754 $6,228 $2,212 47.02% 48.03% $1,075	$19,239 $5,322 $1,397 50.49% 46.62% $583
* The decrease in ownership percentage reflects acquisitions of voting common stock issued by VELCO in amounts below the Company's pro-rata ownership interest at the time.

	Three Months Ended September 30, 2005 2004		Nine Months Ended September 30, 2005 2004
Operating revenues Operating income (loss) Net income Company's ownership interest: 58.85% Company's equity in net income	$41,918 $543 $169 $100	$44,131 $85 $130 $76	$125,227 $(804) $511 $301	$118,328 $(83) $401 $236

	Fair value of debt securities at contractual maturity dates
Debt Securities	Less than 1 year $15,476	1 to 5 years $8,920	5 to 10 years -	After 10 years -	Total $24,396

	Fair value of debt securities at contractual maturity dates
Debt Securities	Less than 1 year $15	1 to 5 years $330	5 to 10 years $270	After 10 years $533	Total $1,148

	Three Months Ended September 30, 2005 2004		Nine Months Ended September 30, 2005 2004
Operating revenues Operating expenses Purchased power Other operating (income) expenses Income tax expense (benefit) Total operating (income) expenses Operating income (loss) Other income, net Net income, net of tax Gain from disposal, net of $8,692 tax for nine months ended Income from discontinued operations, net of tax	$- - - - - - - - - $-	$ - (3) 1 (2) 2 - 2 6 $8	$- - - - - - - - - $-	$24 - 40 (14) 26 (2) 22 20 12,334 $12,354

Three Months Ended September 30,
	CV VT	Catamount Energy Corporation	All Other	Discontinued Operations	Reclassification and Consolidating Entries	Consolidated
2005
Revenues from external customers Intersegment revenues Equity in earnings - utility affiliates (1) Equity in earnings - non-utility affiliates (2) Income (loss) from continuing operations Total assets at September 30, 2005	$75,013 24 485 - 2,871 488,751	$171 - - 27 (250) 67,379	$470 - - - 100 3,953	- - - - - -	$(641) (24) - - - (1,034)	$75,013 - 485 27 2,721 559,049
2004
Revenues from external customers Intersegment revenues Equity income - utility affiliates (1) Equity income - non-utility affiliates (2) Income from continuing operations Income from discontinued operations, net of tax Total assets at December 31, 2004	$72,740 23 410 - 4,515 - 487,567	$126 - - 1,145 1,427 - 61,029	$476 - - - 115 - 15,247	- - - - - 8 -	$(602) (23) - - - - (17,080)	$72,740 - 410 1,145 6,057 8 546,763

2004 Earnings per diluted share		$.47
Year-over-Year Effects on Earnings: Higher retail revenue Higher resale sales Higher purchased power costs Catamount - loss in 2005 versus earnings in 2004 Other Subtotal 2005 Earnings per diluted share	.09 .04 (.19) (.14) (.06)	(.26) $.21

2004 Earnings per diluted share		$1.56
Year-over-Year Effects on Earnings: Higher resale sales Higher retail revenue (a) Regulatory asset amortizations Higher equity in earnings of utility affiliates Catamount - loss in 2005 versus earnings in 2004 Higher purchased power costs (a) (b) Higher transmission and distribution costs IRS tax settlement received in 2004 Higher administrative and general costs Other subtotal Net impact of March 29, 2005 Rate Order recorded in the first quarter of 2005 Net impact of Connecticut Valley sale recorded in 2004: Gain on discontinued operations SFAS No. 5 loss accrual - termination of power contract subtotal 2005 Loss per diluted share (a) excludes effect of first quarter 2005 Rate Order charge which is included in 'Net impact of March 29, 2005 Rate Order recorded in the first quarter of 2005' above (b) excludes first quarter 2004 SFAS No. 5 loss accrual, which is listed separately in 'Net impact of Connecticut Valley sale recorded in 2004' above	.28 .09 .07 .04 (.23) (.19) (.11) (.09) (.08) (.12) (1.01) .69	(.34) (.91) (.32) $(0.01)

	Three Months Ended September 30, 2005 vs. 2004	Nine Months Ended September 30, 2005 vs. 2004
Retail revenues: Volume (mWh) Average price due to customer sales mix Average price due to rate reduction Subtotal Firm resale sales Other resale sales Retail customer refund Other revenues Increase (decrease) in Operating revenues	$4,775 (1,112) (1,871) 1,792 15 859 3 (396) $2,273	$6,024 (611) (3,401) 2,012 (34) 5,759 (6,194) (282) $1,261

	Forward Sale Contract	Hydro-Quebec Sellback #3
Fair value at January 1, 2005 - unrealized gain (loss) Change in fair value, including amounts settled Fair value at September 30, 2005 - unrealized gain (loss)	$385 (15,596) $(15,211)	$(5,735) 456 $(5,279)
Source	Over-the-counter-quotations	Quoted market data & valuation methodologies