CENTRAL VERMONT PUBLIC SERVICE CORP - 10-Q Quarterly Report

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, 2004

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

For the transition period from _______ to _______

Commission file number 1-8222

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

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

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

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

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

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

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. As of October 29, 2004 there were outstanding 12,163,622 shares of Common Stock, $6 Par Value.

Page 1 of 45

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Form 10-Q - 2004

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, 2004 and 2003	3
	Condensed Consolidated Statements of Comprehensive Income (unaudited) for the three and nine months ended September 30, 2004 and 2003	4
	Condensed Consolidated Balance Sheets as of September 30, 2004 (unaudited) and December 31, 2003	5
	Condensed Consolidated Statements of Retained Earnings (unaudited) for the three and nine months ended September 30, 2004 and 2003	7
	Condensed Consolidated Statements of Cash Flows (unaudited) for the nine months ended September 30, 2004 and 2003	8
	Notes to Condensed Consolidated Financial Statements	9
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	42
Item 4.	Controls and Procedures	42
PART II	OTHER INFORMATION	43
SIGNATURES		44
EXHIBIT INDEX		45

Page 2 of 45

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Dollars in thousands, except per share amounts)
(unaudited)

	Three Months Ended September 30		Nine Months Ended September 30
	2004 2003		2004 2003

Operating Revenues	$72,740	$73,839	$224,489	$226,903

Operating Expenses
Operation
Purchased power	35,627	37,097	127,914	114,129
Production and transmission	6,032	6,100	18,800	19,734
Other operation	10,952	9,926	32,832	32,613
Maintenance	4,306	4,540	12,149	11,278
Depreciation	3,972	3,983	12,044	11,927
Other taxes, principally property taxes	3,396	3,324	10,168	9,958
Taxes on income	2,669	3,341	1,428	8,718
Total operating expenses	66,954	68,311	215,335	208,357

Operating Income	5,786	5,528	9,154	18,546
Other Income and Deductions
Equity in earnings of affiliates	410	438	881	1,310
Allowance for equity funds during construction	47	19	95	50
Gain on sale of non-utility investments	1,980	-	1,980	-
Other income, net	556	(909)	4,364	1,555
(Provision) benefit for income taxes	(527)	2,336	(1,712)	1,339
Total other income and deductions, net	2,466	1,884	5,608	4,254

Total Operating and Other Income	8,252	7,412	14,762	22,800
Interest Expense
Interest on long-term debt	2,049	2,802	7,071	8,476
Other interest expense	164	73	164	401
Allowance for borrowed funds during construction	(18)	(8)	(38)	(22)
Total interest expense, net	2,195	2,867	7,197	8,855

Income from continuing operations	6,057	4,545	7,565	13,945
Income from discontinued operations, net of tax (including gain on disposal of $12,334 for nine months ended September 30, 2004)	8	380	12,354	1,034
Net Income	6,065	4,925	19,919	14,979

Dividends on preferred stock	259	300	775	899

Earnings Available for Common Stock	$5,806	$4,625	$19,144	$14,080

Per Common Share Data:
Basic:
Earnings from continuing operations	$0.48	$0.36	$0.56	$1.10
Earnings from discontinued operations	0.00	0.03	1.02	0.09
Earnings per share	$0.48	$0.39	$1.58	$1.19

Diluted:
Earnings from continuing operations	$0.47	$0.35	$0.55	$1.08
Earnings from discontinued operations	0.00	0.03	1.01	0.09
Earnings per share	$0.47	$0.38	$1.56	$1.17

Average shares of common stock outstanding - basic	12,138,847	11,927,894	12,105,248	11,856,742
Average shares of common stock outstanding - diluted	12,296,739	12,200,633	12,276,905	12,083,766

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

Page 3 of 45

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
(unaudited)

	Three Months Ended September 30		Nine Months Ended September 30

	2004	2003	2004	2003
Net Income	$6,065	$4,925	$19,919	$14,979

Other comprehensive income (loss), net of tax:
Foreign currency translation (loss) gain	(330)	(161)	(608)	90
Unrealized gain (loss) on securities	326	14	(144)	(48)
Comprehensive income	$6,061	$4,778	$19,167	$15,021

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

Page 4 of 45

CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)


	September 30 2004	December 31 2003
Assets	(unaudited)

Utility Plant, at original cost	$500,149	$495,162
Less accumulated depreciation	213,922	207,474
Net utility plant	286,227	287,688

Construction work-in-progress	13,598	9,988
Nuclear fuel, net	1,111	1,016
Total utility plant	300,936	298,692

Investments and Other Assets
Investments in affiliates	9,204	9,303
Non-utility investments	26,472	34,765
Non-utility property, less accumulated depreciation	2,143	2,236
Millstone decommissioning trust fund	4,379	4,340
Available for sale securities	22,138	-
Other	5,941	5,249
Total investments and other assets	70,277	55,893

Current Assets
Cash and cash equivalents	37,977	58,147
Restricted cash	648	2,000
Available for sale securities	13,191	-
Notes receivable	17,262	3,750
Accounts receivable, less allowance for uncollectible accounts ($1,373 in 2004 and $1,578 in 2003)	18,648	21,900
Unbilled revenues	12,648	17,505
Materials and supplies, at average cost	3,580	3,699
Prepayments	2,696	3,226
Other current assets	3,103	2,522
Assets held for sale	-	9,292
Total Current Assets	109,753	122,041

Deferred Charges and Other Assets
Regulatory assets	14,428	17,555
Other deferred charges - regulatory	33,284	30,929
Other	5,985	6,209
Total deferred charges and other assets	53,697	54,693

Total Assets	$534,663	$531,319

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

Page 5 of 45

CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in thousands)


	September 30 2004	December 31 2003
Capitalization and Liabilities	(unaudited)

Capitalization
Common stock, $6 par value, authorized 19,000,000 shares (issued 12,126,188 and 11,807,495)	$72,765	$72,119
Other paid-in capital	50,452	51,334
Accumulated other comprehensive income	(267)	485
Deferred compensation plans - employee stock ownership plans	133	(969)
Retained earnings	99,862	88,282
Total common stock equity	222,945	211,251
Preferred and preference stock	8,054	8,054
Preferred stock with sinking fund requirements	7,000	9,000
Long-term debt	126,750	126,750
Capital lease obligations	9,870	10,693
Total capitalization	374,619	365,748

Current Liabilities
Current portion of preferred stock	1,000	1,000
Current portion of long-term debt	-	2,657
Accounts payable	2,910	6,650
Accounts payable - affiliates	9,804	10,985
Accrued income taxes	378	196
Accrued interest	1,599	2,801
Nuclear decommissioning costs	4,807	4,026
Other current liabilities	19,353	18,697
Liabilities of assets held for sale	-	5,499
Total current liabilities	39,851	52,511

Deferred Credits and Other Liabilities
Deferred income taxes	32,976	36,713
Deferred investment tax credits	4,573	4,880
Nuclear decommissioning costs	18,842	22,934
Asset retirement obligations	3,594	3,449
Other	60,208	45,084
Total deferred credits and other liabilities	120,193	113,060

Commitments and Contingencies

Total Capitalization and Liabilities	$534,663	$531,319

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

Page 6 of 45

CONDENSED CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

(Dollars in thousands)
(unaudited)

	Three Months Ended September 30		Nine Months Ended September 30
	2004 2003		2004 2003
Retained Earnings at Beginning of Period	$94,062	$81,755	$88,282	$80,077
Net Income from continuing operations	6,057	4,545	7,565	13,945
Net Income from discontinued operations	8	380	12,354	1,034
Retained Earnings Before Dividends	100,127	86,680	108,201	95,056

Cash Dividend Declared
Preferred Stock	259	300	775	899
Common Stock	6	-	8,344	7,814
Total Dividends Declared	265	300	9,119	8,713
Performance Share Plan	-	-	780	-
Other Adjustments	-	(8)	-	29
Retained Earnings at End of Period	$99,862	$86,372	$99,862	$86,372

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

Page 7 of 45

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

	Nine Months Ended September 30
	2004	2003
Cash Flows Provided (Used) By:
Operating Activities
Net income from continuing operations	$7,565	$13,945
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of affiliates	(881)	(1,310)
Dividends received from affiliates	863	1,041
Equity in earnings from non-utility investments	(3,747)	(4,579)
Distribution of earnings from non-utility investments	9,016	10,211
Depreciation	12,045	11,927
Amortization of capital leases	823	823
Deferred income taxes and investment tax credits	(1,519)	(2,548)
Reversal of deferred income tax valuation allowance	-	(2,293)
Net amortization of nuclear replacement energy and maintenance costs	(754)	491
Amortization of conservation and load management costs	58	1,438
Reserve for loss on power contract (SFAS No. 5 loss accrual)	14,351	-
Amortization of SFAS 5 loss accrual	(897)	-
Vermont Yankee replacement energy deferral	(834)	-
Gain on sale of non-utility investments	(1,980)	-
Decrease in accounts receivable and unbilled revenues	5,487	3,836
Decrease in accounts payable	(4,459)	(1,616)
(Decrease) increase in accrued income taxes	(9,555)	1,175
Increase in other current assets	(262)	(950)
(Decrease) increase in other current liabilities	(97)	144
Increase in pension and benefit obligations	2,141	2,521
Decrease in other long-term assets	2,973	2,823
Decrease in other long-term liabilities and other	(6,497)	(555)
Increase in restricted cash - Renewable Development Trust Fund	(648)	-
Net cash provided by operating activities of continuing operations	23,192	36,524
Investing Activities
Construction and plant expenditures	(15,195)	(10,507)
Conservation and load management expenditures	(93)	(102)
Return of capital	196	70
Utility investments	-	(177)
Non-utility investments	(16,926)	-
Increase in restricted cash for non-utility investment	-	(10,099)
Proceeds from sale of non-utility investments	4,571	-
Investments in available for sale securities	(35,595)	-
Other investments, net	180	(228)
Net cash used for investing activities of continuing operations	(62,862)	(21,043)
Financing Activities
Proceeds from exercise of stock options	498	1,434
Proceeds from dividend reinvestment program	1,458	1,373
Proceeds from issuance of long-term debt	75,000	-
Retirement of long-term debt	(77,660)	(15,367)
Decrease in restricted cash - preferred stock	2,000	-
Retirement of preferred stock	(2,000)	-
Common and preferred dividends paid	(9,119)	(8,413)
Reduction in capital lease obligations	(823)	(823)
Net cash used for financing activities of continuing operations	(10,646)	(21,796)

Effect of exchange rate changes on cash	(18)	(516)

Cash flows provided by (used for) discontinued operations	30,164	(242)

Net Decrease in Cash and Cash Equivalents	(20,170)	(7,073)
Cash and Cash Equivalents at Beginning of Year	58,147	60,364
Cash and Cash Equivalents at End of Year	$37,977	$53,291
Supplemental Cash Flow Information
Cash paid during the year for:
Interest (net of amounts capitalized)	$7,956	$9,679
Income taxes (net of refunds)	$14,531	$11,935

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

Page 8 of 45

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

About Central Vermont Public Service Corporation Central Vermont Public Service Corporation (the "Company") is a Vermont-based electric utility that transmits, distributes and sells electricity, and invests in renewable and independent power projects. The Company's wholly owned subsidiaries include: Catamount Energy Corporation ("Catamount"), which invests primarily in wind energy projects in the United States and the United Kingdom; Eversant Corporation ("Eversant"), which operates a rental water heater business through its subsidiary, SmartEnergy Water Heating Services, Inc.; and Connecticut Valley Electric Company Inc. ("Connecticut Valley"), which completed the sale of substantially all of its plant assets and franchise on January 1, 2004. Prior to the sale, Connecticut Valley distributed and sold electricity in parts of New Hampshire. See Note 4 - Discontinued Operations.

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by accounting principles generally accepted in the United States of America ("GAAP") for financial statements. In management's opinion, all adjustments considered necessary for a fair presentation have been included. Operating results for the third quarter and first nine months of 2004 are not necessarily indicative of the results that may be expected for the 12 months ended December 31, 2004. 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, 2003 and its other Securities and E xchange Commission 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 its FERC-regulated wholesale business. Based on a current evaluation of the factors and conditions expected to affect future cost recovery, management believes future recovery of the Company's regulatory assets in the State of Vermont and wholesale business is probable.

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 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 Company would be required to write off related regulatory assets, certain other deferred charges and regulatory liabilities that are summarized in the table that follows (in thousands):

	September 30, 2004	December 31, 2003
Net Regulatory Assets, Deferred Charges and Regulatory Liabilities
Regulatory assets *
Conservation and load management ("C&LM")	$589	$517
Nuclear refueling outage costs - Millstone	863	109
Income taxes	4,340	5,640
Maine Yankee nuclear power plant dismantling costs (a)	6,163	7,287
Connecticut Yankee nuclear power plant dismantling costs (a)	2,325	2,980
Unrecovered plant and regulatory study costs (b)	-	874
Other regulatory assets	148	148
Subtotal Regulatory assets	14,428	17,555

Other deferred charges - regulatory
Vermont Yankee fuel rod maintenance deferral **	3,317	3,101
Vermont Yankee sale costs **	9,110	8,704
Vermont Yankee replacement energy deferral (c)	834	-
Yankee Atomic incremental dismantling costs (a)	7,187	7,481
Connecticut Yankee incremental dismantling costs (a)	10,483	10,347
Unrealized loss on power contract derivatives	2,353	1,296
Subtotal Other deferred charges - regulatory	33,284	30,929




Page 9 of 45
Other deferred credits ***
Millstone Decommissioning	544	304
IPP Settlement Reimbursement and VEPPI cost mitigation	1,092	757
Vermont utility mandated earnings cap	3,445	3,220
Vermont Yankee NEIL Insurance refund (d)	649	461
Asset Retirement Obligation - Millstone Unit #3	784	891
Unrealized gain on power contract derivative	-	444
Other regulatory liabilities	534	602
Subtotal Other deferred credits	7,048	6,679

Net Regulatory assets, deferred charges and other deferred credits	$40,664	$41,805

* Regulatory assets are currently being recovered in rates and, with the exception of C&LM and Other regulatory assets, include an associated return. These items include a provision for carrying costs and will be addressed in the Company's pending rate proceeding, per the approved PSB Accounting Orders that are associated with them. * Included in Other in Deferred Credits and Other Liabilities on the Condensed Consolidated Balance Sheets.

Regulatory assets related to Connecticut Yankee and Maine Yankee represent estimated decommissioning costs that are being collected from the Company's customers through its existing retail rate tariffs. The estimated incremental dismantling costs for these facilities and for Yankee Atomic that are not included in retail rates are recorded as deferred charges. In October 2003, the PSB approved an Accounting Order for treatment of these incremental costs as deferred charges, to be addressed in the Company's pending rate proceeding. Also see Note 11 - Commitments and Contingencies.
The Company had been recovering costs related to its past investment in Seabrook through its wholesale power contract with Connecticut Valley. The contract was terminated on January 1, 2004 as a result of the Connecticut Valley sale, and the remaining regulatory asset was written off in the first quarter of 2004. The write-off of the assets reduced the reported gain on the sale. See Note 4 - Discontinued Operations.
On July 12, 2004, the PSB approved the Company's request for a preliminary Accounting Order for deferral of incremental replacement power costs incurred as a result of Vermont Yankee's unscheduled outage resulting from a June 2004 transformer fire at the plant. The plant was offline from June 18 through July 7, 2004. In the second quarter of 2004, based on a preliminary Accounting Order, the Company deferred about $0.6 million of incremental replacement power costs incurred for the outage period in June. In the third quarter the Company deferred an additional $0.2 million for the outage period in July. The PSB's approval included the following two provisions: 1) it did not allow for recovery of carrying costs; and 2) it required monthly amortization over a three-year period beginning July 1, 2004. On July 23, 2004, the Company filed a Motion for Reconsideration and requested an immediate temporary stay related to these provisions. On July 28, 2004, the PSB granted the Company's request and stayed t he two provisions until the PSB issues a Final Accounting Order, which will be addressed in the Company's pending rate proceeding.
Pursuant to PSB approval of the Vermont Yankee sale, distributions from Nuclear Electric Insurance Limited ("NEIL") received by Vermont Yankee and passed to the Company and one other sponsor company must benefit ratepayers through programs to promote renewable resources. On April 7, 2004, the PSB approved the Company's plan for use of these funds, which included a $0.2 million grant to the Vermont Small Wind Solar Fund, and the remaining balance of $0.6 million for creation of a Renewable Development Trust Fund. On July 30, 2004, the PSB issued an Order that approved the Company's Voluntary Renewable Pricing Program, "CVPS Cow Power."

Other Deferred Credits The Company's other deferred credits and other liabilities include the following (in thousands):

	September 30, 2004	December 31, 2003
Accrued pension benefits	$13,836	$12,562
Accrued postretirement medical and other benefits	8,745	7,877
Environmental reserve (long-term portion)	4,741	5,983
Non-legal asset retirement obligation	5,950	5,226
Other deferred credits - regulatory	7,048	6,679
Deferred tax liabilities	4,427	4,451
Reserve for loss on power contract	12,258	-
Other	3,203	2,306
Total	$60,208	$45,084

Page 10 of 45

Other Current Liabilities The Company's miscellaneous current liabilities include the following (in thousands):

	September 30, 2004	December 31, 2003
Accrued employee costs - payroll and medical	$3,366	$3,373
Other taxes and Energy Efficiency Utility	3,605	3,254
Deferred compensation plans	2,673	2,749
Customer deposits, prepayments and interest	1,336	2,021
Obligation under capital leases	1,097	1,097
Environmental and accident reserves	2,225	1,755
Accrued joint-owned expenses	203	302
Reserve for loss on power contract	1,196	-
Miscellaneous accruals	3,652	4,146
Total	$19,353	$18,697

Discontinued Operations The assets and liabilities of Connecticut Valley are classified as held for sale in the Condensed Consolidated Balance Sheets in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, ("SFAS No. 144") as of December 31, 2003. The results of operations related to Connecticut Valley are reported as discontinued operations, and prior periods have been restated to conform to this presentation. For presentation purposes, certain of the Company's common corporate costs, which were previously allocated to Connecticut Valley, have been reallocated back to continuing operations to reflect the sale's impact on continuing operations. We began to present Connecticut Valley as discontinued operations in the second quarter of 2003 based on the New Hampshire Public Utility Commission's ("NHPUC") approval of the sale of Connecticut Valley's plant assets and franchise to Public Service Company of New Hampshire ("PSNH"). See Note 4 - Disconti nued Operations.

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

The loss accrual was estimated based on significant variables including assumptions about future power prices, the reallocation of power from the state-appointed purchasing agent ("VEPPI") and future load growth. Management will review this estimate at the end of each reporting period, and will increase the reserve if the revised estimate exceeds the recorded loss accrual. Additionally, the loss accrual will be reversed and amortized on a straight-line basis through 2015, as required by GAAP. This amounted to $0.9 million for the nine months ended September 30, 2004.

Stock Based Compensation The Company applies Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and related Interpretations in accounting for its stock option plans. In accordance with SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of SFAS No. 123, the following table 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 for the third quarter and first nine months of 2004 and the binomial option-pricing model for the same periods in 2003. This change in methodology did not materially alter the results of the computation.

(in thousands, except per share amounts)	Three Months Ended September 30		Nine Months Ended September 30
	2004	2003	2004	2003
Earnings available for common stock, as reported	$5,806	$4,625	$19,144	$14,080
Deduct: Total stock-based employee compensation*	23	18	236	153

Pro forma net income	$5,783	$4,607	$18,908	$13,927

Earnings per share:
Basic - as reported	$0.48	$0.39	$1.58	$1.19
Basic - pro forma	$0.48	$0.39	$1.56	$1.17

Diluted - as reported	$0.47	$0.38	$1.56	$1.17
Diluted - pro forma	$0.47	$0.38	$1.54	$1.15

* Fair value-based method for all awards, net of related tax effects.

Page 11 of 45

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

Restricted Cash The Company used $2 million of restricted cash in January 2004 to redeem preferred stock, including a $1 million mandatory sinking fund payment for 2004 and a $1 million optional payment. Restricted cash of $0.6 million as of September 30, 2004 is for a Renewable Development Trust fund described in Regulatory Accounting above.

Reclassifications The Company will record reclassifications to the financial statements of the prior year when considered necessary or to conform to current-year presentation.

Recent Accounting Pronouncements

Medicare Prescription Drug, Improvement and Modernization Act of 2003: See Note 9 - Pension and Postretirement Benefits.

Investments in Debt and Equity Securities not Accounted for Using the Equity Method: In June 2004, the FASB issued EITF 03-1, The Meanings of Other-Than-Temporary Impairment and Its Application to Certain Investments ("EITF 03-1"), which prescribes a common approach to evaluating other-than-temporary impairment of investments in debt and equity securities not accounted for using the equity method of accounting for certain equity investments. Implementation of EITF 03-1 has been effectively delayed by FASB Staff Position ("FSP") EITF Issue 03-1-1, Effective Date of Paragraphs 10-20 of EITF Issue No. 03-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments until the guidance contained in proposed FSP EITF Issue 03-1-a, Implementation Guidance for the Application of Paragraph 16 of EITF Issue No. 03-1 ("FSP EITF 03-1-a") has been finalized. Until a final version of the implementation guidance contained in FSP EITF 03-1-a is avail able, the Company cannot predict the impact, if any, the adoption of EITF 03-1 will have on its financial statements.

NOTE 2 - INVESTMENTS IN AFFILIATES

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

	Three Months Ended September 30		Nine Months Ended September 30
Earnings	2004	2003	2004	2003
Operating revenues	$44,131	$45,342	$118,328	$142,324
Operating income (loss)	$85	$305	$(83)	$859
Net income	$130	$762	$401	$2,169

Company's equity in net income	$76	$253	$236	$721

In November 2003, the Company's ownership interest in VYNPC increased from 33.23 percent to 58.85 percent as a result of the repurchase of shares held by certain non-Vermont sponsors. The non-Vermont sponsors remain obligated under all agreements with VYNPC, including their power purchase obligations under the VYNPC power contract with Entergy Nuclear Vermont Yankee, LLC ("ENVY"). Although the Company owns a majority of the shares of VYNPC, the Power Contracts, Sponsor Agreement and composition of the Board of Directors, under which it operates, effectively restrict the Company's ability to exercise control over VYNPC. Additionally, the Company has concluded, based on provisions of FASB Interpretation No. 46, Consolidation of Variable Interest Entities, as revised ("FIN 46R"), that it is not VYNPC's primary beneficiary. Therefore, its financial statements have not been consolidated into the Company's financial statements.

VYNPC's revenues shown in the table above include sales to the Company of $15.4 million for the third quarter and $41.7 million for the first nine months of 2004, and $16.3 million and $50 million for the same periods in 2003.

Page 12 of 45

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

	Three Months Ended September 30		Nine Months Ended September 30
Earnings	2004	2003	2004	2003
Transmission revenues	$6,363	$5,890	$19,239	$17,160
Operating income	$2,121	$1,379	$5,322	$4,129
Net income	$779	$289	$1,397	$911

Company's equity in net income	$308	$153	$583	$482

The Company's common stock ownership (voting and non-voting) changed from 50.6 percent to 50.5 percent in the third quarter of 2003. Although the Company owns 50.5 percent of VELCO's outstanding common stock, the Four-Party Agreement between the owners of VELCO does not provide the Company with the ability to exercise control over VELCO. The Company has evaluated its relationship with VELCO under the requirements of FIN 46R and has determined that it is not the primary beneficiary. Therefore, its financial statements have not been consolidated into the Company's financial statements.

VELCO's revenues shown in the table above include transmission services to the Company (reflected as production and transmission expenses in the Company's Condensed Consolidated Statements of Income) totaling $0.3 million for the third quarter and $5.5 million for the first nine months of 2004, and $2.4 million and $8.1 million for the same periods in 2003.

Other Affiliates The Company has equity ownership interests in three nuclear plants, including 2 percent in Maine Yankee Atomic Power Company ("Maine Yankee"), 2 percent in Connecticut Yankee Atomic Power Company ("Connecticut Yankee"), and 3.5 percent in Yankee Atomic Electric Company ("Yankee Atomic"). These plants are permanently shut down and are conducting decommissioning activities. The Company's obligations related to these plants are described in Note 11 - Commitments and Contingencies.

NOTE 3 - NON-UTILITY INVESTMENTS

Catamount As of September 30, 2004, Catamount had interests in seven operating independent power projects located in Rumford, Maine; East Ryegate, Vermont; Hopewell, Virginia; Nolan County, Texas; Thetford, England; Thuringen, Germany; and Mecklenburg-Vorpommern, Germany.

Catamount has projects under development in the United States and United Kingdom. In July 2003, Catamount established Catamount Cymru Cyf., an English and Welsh private limited company, to develop a project located in Wales. 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 of shares resulted in no gain or loss.

As of September 30, 2004, Catamount had Notes Receivable of $17.3 million, of which $16.5 million is related to construction of a wind project in the United States under a construction lending arrangement described in more detail in Note 11 - Commitments and Contingencies. Of the remaining amount, $0.3 million is related to development of a wind site in the United States and $0.5 million is related to development of United Kingdom wind sites through Catamount's joint venture company.

Additional information regarding certain of Catamount's investments follows.

Glenns Ferry and Rupert On July 1, 2004, Catamount completed the sale of its investment interests in Glenns Ferry and Rupert to a third party. The sale resulted in an after-tax gain of about $0.6 million and an additional $0.2 million of income tax benefits associated with the sale.

Fibrothetford Limited ("Fibrothetford") In September 2004, Catamount entered into separate Sales and Purchase Agreements with third parties for the sale of its Fibrothetford note receivable and equity investment. The note receivable was sold in September 2004, resulting in an after-tax gain of $0.6 million and an additional $0.2 million of income tax benefits associated with the sale.

Catamount sold its Fibrothetford equity investment on October 18, 2004, resulting in an after-tax gain of about $0.3 million and an additional $2.5 million of income tax benefits, both of which will be recorded in the fourth quarter of 2004.

Page 13 of 45

Eversant As of September 30, 2004, Eversant had a $1.4 million investment, representing a 12 percent ownership interest, in the Home Service Store, Inc. ("HSS"), which has established a network of affiliate contractors who perform home maintenance repair and improvements for HSS members. Eversant accounts for this investment on the cost basis.

NOTE 4 - 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.

Cash proceeds from the sale amounted to about $30 million, with $9 million representing the net book value of Connecticut Valley's plant assets plus certain other adjustments, and $21 million as described below. In return, PSNH acquired Connecticut Valley's franchise, poles, wires, substations and other facilities, and several independent power obligations, including the Wheelabrator contract.

As a condition of the sale, Connecticut Valley paid the Company $21 million to terminate its long-term power contract. In the first quarter of 2004, in accordance with SFAS No. 5, the Company recorded a $14.4 million pre-tax loss accrual related to termination of the power contract. The loss accrual represents management's best estimate of the difference between expected future sales revenue, in the wholesale market, for the purchased power that was formerly sold to Connecticut Valley and the cost of purchased power to be incurred to realize those future sales. In accordance with GAAP, the loss accrual will be reversed and amortized on a straight-line basis through 2015, which represents the estimated life of the Company's power contracts that were in place to supply power to Connecticut Valley.

For the first nine months of 2004, income from discontinued operations totaled $12.3 million, including a gain on disposal of discontinued operations of about $21 million, pre-tax, or $12.3 million, after-tax. The gain reflects the $30 million payment from PSNH, net of various other adjustments. In the third quarter of 2004, discontinued operations recorded various minor adjustments to complete activities under the sale agreements.

For accounting purposes, components of the sale transaction are recorded in both continuing and discontinued operations in the consolidated income statement. In addition to the gain on the asset sale, described above, the Company recorded a loss on power costs, net of tax, of $8.4 million relating to termination of the power contract with Connecticut Valley. When the two accounting transactions are combined to assess the total impact of the sale, the result is a gain of $3.9 million recorded in 2004.

Summarized results of operations of the discontinued operations are as follows (in thousands):

Three Months Ended
September 30

Nine Months Ended
September 30

    2004

     2003

    2004

     2003

Operating revenues

-

$4,951

$24

$14,754

Operating expenses

   Purchased power

-

3,741

-

11,137

   Other operating (income) expenses

$(3)

465

40

1,484

   Income tax expense (benefit)

  1

   305

(14)

     884

   Total operating (income) expenses

(2)

4,511

26

13,505

Operating income (loss)

2

440

(2)

1,249

Other (expense) income, net

  -

   (60)

22

   (215)

Net income, net of tax

2

380

20

1,034

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

  6

       -

12,334

         -

Income from discontinued operations, net of tax

$8

$380

$12,354

$1,034

Page 14 of 45

The major classes of Connecticut Valley's assets and liabilities reported as discontinued operations on the Condensed Consolidated Balance Sheets are as follows (in thousands):

September 30

December 31

2004

2003

Assets

         Net utility plant

$    -

$9,251

         Other current assets

      -

       41

         Total assets of discontinued operations

$    -

$9,292

Liabilities

         Accounts payable

$     -

$1,749

         Short-term debt (a)

       -

  3,750

         Total liabilities of discontinued operations

$     -

$5,499

(a) Related to a Note Payable due to the Company that was paid on January 1, 2004.

FERC Exit Fee Proceedings The January 1, 2004 termination of the wholesale power contract between the Company and Connecticut Valley resolved the Company's FERC litigation related to a February 1997 NHPUC Order in which it told Connecticut Valley to stop buying power from the Company.

Wheelabrator Power Contract Connecticut Valley had sought relief from the NHPUC related to its concern that Wheelabrator had not been a qualifying facility since it began operation. PSNH acquired Connecticut Valley's independent power obligations, including the Wheelabrator contract, as part of the January 1, 2004 sale described above, thus resolving this issue.

NOTE 5 - AVAILABLE FOR SALE SECURITIES

The Company invested proceeds received from the Connecticut Valley sale, in addition to other cash on hand, in available for sale securities with various maturities. At September 30, 2004, these investments included $13.2 million with maturities of one year or less and $22.1 million with maturities greater than one year. Investments with maturities of one year or less are included in Current Assets on the Condensed Consolidated Balance Sheet, while those with maturities greater than one year are included in Investments and Other Assets. These available for sale securities are subject to SFAS 115, Accounting for Certain Investments in Debt and Equity Securities, and are reported at fair value. Realized gains and losses are included in interest income and unrealized gains and losses are recorded in other comprehensive income. Information regarding available for sale securities as of September 30, 2004 follows (in thousands):

		FAIR VALUE
Security Types	Original Cost	Current Assets	Long-term Assets	Total	Unrealized Gains	Unrealized Losses

US Government Obligations	$5,026	$5,018	-	$5,018	-	$8
US Government Agencies	22,126	4,073	$17,865	21,938	-	188
Corporate Bonds	8,443	4,100	4,273	8,373	-	70
Total	$35,595	$13,191	$22,138	$35,329	-	$266

NOTE 6 - LONG-TERM DEBT

Utility During the second quarter of 2004, the Company received regulatory approvals and waivers needed to issue First Mortgage Bonds to refinance and replace the $75 million of Second Mortgage Bonds that matured on August 1, 2004. On May 28, 2004, the Company priced such First Mortgage Bonds. Pursuant to such pricing, on July 30, 2004, the Company issued $20 million of 5 percent First Mortgage Bonds, due in 2011, and $55 million of 5.72 percent First Mortgage Bonds, due in 2019. The proceeds were used to repay in full the $75 million of 8.125 percent Second Mortgage Bonds.

The Company extended $16.9 million of unsecured letters of credit to November 30, 2005. These letters of credit support three series of Industrial Development/Pollution Control Bonds, totaling $16.3 million.

Based on outstanding debt at September 30, 2004, no principal payments are due on long-term debt from 2005 through 2007. At September 30, 2004, substantially all utility property and plant were subject to liens under the First Mortgage Bonds and the Company was in compliance with all debt covenants.

Page 15 of 45

Non-Utility In January 2004, Catamount paid off a $2.5 million balance on its term loan, and in February 2004, Catamount notified the lender of its intent to terminate the credit facility. Effective May 16, 2004, the credit facility was officially terminated. Catamount's office building mortgage matured on April 15, 2004 and Catamount paid the outstanding balance in full.

NOTE 7 - RETAIL RATES

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

Vermont Retail Rates The Company's current retail rates are based on a June 26, 2001 PSB Order approving a settlement with the Vermont Department of Public Service ("DPS") that provided for, among other things, a 3.95 percent rate increase effective July 1, 2001, and an allowed return on common equity of 11 percent for the year ended June 30, 2002 (capped through January 1, 2004).

In April 2003, the Company prepared cost of service studies for rate years 2003 and 2004, in accordance with the PSB's approval of the Vermont Yankee sale. The purpose of those filings was to determine whether a rate decrease was warranted

in either year as a result of the sale of the Vermont Yankee plant. In July 2003, the Company agreed to a Memorandum of Understanding ("MOU") with the DPS regarding that filing. The MOU concluded that: 1) a rate decrease was not warranted; 2) the Company would decrease its allowed return on common equity from 11 percent to 10.5 percent effective July 1, 2003; 3) any earnings over the allowed cap of 10.5 percent would be applied to reduce deferred charges on the balance sheet; 4) the Company would file a fully allocated cost of service plan and a proposed rate redesign; and 5) the Company agreed to work cooperatively with the DPS to develop and propose an alternative regulation plan.

Hearings on the MOU were conducted by the PSB in December 2003, and the PSB issued an Order on January 27, 2004 providing conditional approval for the MOU. It included the following significant modifications: 1) that the allowed return on common equity be reduced to 10.25 percent; 2) starting January 1, 2004 the Company would begin new amortizations of deferred charges on the balance sheet at December 31, 2003 of about $2.5 million annually; and 3) that the Company would file with the PSB a proposal to apply the $21 million payment it received in connection with the Connecticut Valley sale to write down deferred charges.

On February 3, 2004, the Company filed a Request for Reconsideration and Clarification, and in March 2004 participated in a workshop to review the filing. On April 7, 2004, the PSB denied the Company's request. While the PSB agreed to remove the third modification, absent the Company's acceptance of the remaining modifications, the PSB concluded that it would open a rate investigation. Consequently, the PSB issued an Order Opening Investigation and Notice of Prehearing Conference in Docket No. 6946 to investigate the Company's current rates.

On July 15, 2004, the Company filed a cost of service in the rate investigation that demonstrates a rate deficiency of 2.4 percent, and recommends that rates should not be decreased retroactively to April 1, 2004. Also on July 15, 2004, the Company filed its request with the PSB for a 5.01 percent rate increase, expected to be effective April 1, 2005, and requested that the two cases be consolidated.

On September 8, 2004, the PSB consolidated the two cases and confirmed a schedule for proceedings through 2004, with a final order in March 2005.

On October 1, 2004, the DPS filed its testimony with the PSB related to the rate investigation and the Company's request for a rate increase. The DPS's major findings and recommendations include: 1) a rate refund to the Company's rate payers retroactive to April 1, 2004 of 4.65 percent or $12 million; and 2) a rate reduction of 5.93 percent or almost $16 million on an annual basis effective with service rendered April 1, 2005.

On October 1, 2004, AARP, an intervener in the case, filed testimony that supports a rate increase of up to 3.5 percent effective April 1, 2005.

Technical hearings with the PSB were held the week of November 1, 2004. At this time, the Company cannot predict the outcome of the rate investigation or its request for a 5.01 percent rate increase.

Page 16 of 45

NOTE 8 - RECONCILIATION OF NET INCOME AND AVERAGE SHARES OF COMMON STOCK

A reconciliation of net income to net income available for common stock and average common shares outstanding basic to diluted follows (in thousands):

	Three Months Ended September 30		Nine Months Ended September 30
	2004	2003	2004	2003
Income from continuing operations	$6,057	$4,545	$7,565	$13,945
Income from discontinued operations, net of tax	8	380	12,354	1,034
Net Income	6,065	4,925	19,919	14,979
Preferred stock dividend requirements	259	300	775	899
Earnings available for common stock	$5,806	$4,625	$19,144	$14,080

Average shares of common stock outstanding - basic	12,138,847	11,927,894	12,105,248	11,856,742
Dilutive effect of stock options	129,447	160,727	143,212	115,012
Dilutive effective of performance plan shares	28,445	112,012	28,445	112,012
Average shares of common stock outstanding - diluted	12,296,739	12,200,633	12,276,905	12,083,766

NOTE 9 - PENSION AND POSTRETIREMENT BENEFITS
The Company records pension and other postretirement benefit costs in accordance with SFAS No. 87, Employers' Accounting for Pensions, and SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions. Under these accounting standards, assumptions are made regarding the valuation of benefit obligations and performance of plan assets. Delayed recognition of differences between actual results and those assumed is a required principle of these standards. This approach allows for systematic recognition of changes in benefit obligations and plan performance over the working lives of the employees who benefit under the plans. The following is a list of the primary assumptions, which are updated at the end of each year, for a September 30 measurement date.

Discount Rate - The discount rate is used to record the value of benefits, which are based on future projections, in terms of today's dollars. As of September 30, 2003, the discount rate was decreased from 6.5 percent to 6 percent, in light of long-term interest rates remaining at historically low levels.

Expected Return on Plan Assets ("ROA") - The Company projects the future ROA based principally on historical returns by asset category and expectations for future returns, in part on simulated capital market performance over the next 10 years. The projected future value of assets reduces the benefit obligation a company will record. At September 30, 2002, the ROA changed from 8.5 percent to 8.25 percent. This rate was used to determine the annual expense for 2003 and the same rate was used to determine the 2004 expense.

Rate of Compensation Increase - The Company projects employees' annual pay increases, which are used to project employees' pension benefits at retirement. As of September 30, 2003, the rate of compensation increase was changed from 4 percent to 3.75 percent based on lower than previously projected trends in cost-of-living increases.

Health Care Cost Trend - The Company projects expected increases in the cost of health care. For measurement purposes, the Company assumed a 12 percent annual rate of increase in the per capita cost of covered health care benefits for pre-65 claims, and an 11.5 percent increase for post-65 claims, for fiscal 2004. These assumptions were based on expected higher health care costs.
Amortization of Gains/(Losses) - The Company can select the method by which gains or losses are recognized in financial results. These gains or losses are created when actual results differ from estimated results based on the above assumptions. The Company recognizes these gains and losses ratably over a five-year period.

Page 17 of 45

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

Pension Benefits	Three Months Ended September 30		Nine Months Ended September 30
	2004	2003	2004	2003
Service cost	$755	$686	$2,265	$2,058
Interest cost	1,388	1,371	4,164	4,113
Expected return on plan assets	(1,406)	(1,489)	(4,218)	(4,467)
Amortization of prior service cost	99	99	297	297
Amortization of transition asset	(37)	(37)	(111)	(111)
Net periodic benefit cost	799	630	2,397	1,890
Less amount allocated to other accounts	139	106	390	318
Net benefit costs expensed	$660	$524	$2,007	$1,572

Postretirement Benefits	Three Months Ended September 30		Nine Months Ended September 30
	2004	2003	2004	2003
Service cost	$135	$105	$405	$315
Interest cost	389	327	1,167	981
Expected return on plan assets	(108)	(77)	(324)	(231)
Recognized net actuarial loss	345	211	1,035	633
Amortization of transition obligation	64	64	192	192
Net periodic benefit cost	825	630	2,475	1,890
Less amount allocated to other accounts	144	106	403	318
Net benefit costs expensed	$681	$524	$2,072	$1,572

Plan Assets Pension costs and cash funding requirements are expected to increase in future years. At September 30, 2004, the market value of pension plan trust assets was $61.5 million, including $40.9 million in marketable equity securities, $20.3 million in debt securities and $0.3 million in cash and accrued income. At December 31, 2003, pension plan trust assets were $61.3 million, including $42.5 million in marketable equity securities and $18.8 million in debt securities.

Employer Contributions In the third quarter of 2004, the Company made the minimum pension contribution of $1.1 million for the 2003 plan year. There was no pension contribution payment made in 2003. For the first nine months of 2004, the Company paid $1.7 million for net postretirement benefits, compared to $1.4 million for the same period in 2003. The Company expects annual 2004 contributions of $3.3 million compared to annual 2003 contributions of $2.5 million.

Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the "Act") On May 19, 2004, the FASB issued FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, ("FAS No. 106-2") which superseded FSP 106-1, which allowed employers to voluntarily recognize the impact of the Act. This was in response to a new law regarding prescription drug benefits under Medicare ("Medicare Part D") and a federal subsidy to sponsors of retiree health care benefit plans that are at least actuarially equivalent to Medicare Part D. Currently, SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, requires that changes in relevant law be considered in current measurement of postretirement benefit costs. The Company had elected to defer recognition of any impact under FSP 106-1. FSP 106-2 provides that if the effect of the Act is not considered a sign ificant event, the measurement date for adoption of FSP 106-2 is delayed until the next regular measurement date. Although the September 30, 2004 valuation is not complete, the annual savings are estimated to be about $0.3 million and therefore, the Company has concluded that the effect is not significant. As such, measures of the accumulated postretirement benefit obligation and the net periodic postretirement benefit cost do not reflect the effects of the new law.

NOTE 10 - INCOME TAXES

Income tax expense is based on estimated annual effective tax rates, which differ from the federal statutory rate of 35 percent, primarily due to state and local income taxes, nondeductible expenses, the dividends received deduction, life insurance and other items.

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, which reduced regulatory tax assets by about $1 million, and increased state income tax expense by about $0.1 million in the second quarter of 2004.

Page 18 of 45

For the first nine months of 2004 taxes on income includes a $5.5 million benefit related to the SFAS No. 5 loss accrual as described in Note 4 - Discontinued Operations.

In the second quarter of 2004, the Company received $1.8 million from an income tax settlement related to an appeal for a refund of an overpayment from a prior audit for the tax years 1982 through 1984. The proceeds included federal income tax of $0.5 million, interest expense of $0.4 million that was previously paid, and $0.9 million of interest income on the refunds. The settlement, net of legal fees and tax on the interest income, resulted in a $1.1 million favorable effect on 2004 results.

In the third quarter of 2004, Catamount completed the sale of its Glenns Ferry and Rupert investment interests and its Fibrothetford note receivable. As a result of the sales and structure changes at each of the investments, Catamount recorded an additional $0.4 million of tax benefits.

Previously in the third quarter of 2003, Catamount reduced income tax valuation allowances, associated with previously recorded equity losses resulting from asset impairments, by $2.3 million. This was the result of a benefit in the consolidated federal income tax provision due to management's best estimate that the Company would receive capital gains treatment on the Connecticut Valley sale.

NOTE 11 - COMMITMENTS AND CONTINGENCIES

Nuclear Decommissioning The Company is responsible for its joint ownership share in Millstone Unit #3 decommissioning costs as described below. The Company is also one of several sponsor companies with ownership interests in Maine Yankee, Connecticut Yankee and Yankee Atomic, and is responsible for paying its ownership percentage of decommissioning and all other costs for each plant. All four 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. Maine Yankee, Connecticut Yankee and Yankee Atomic are parties to a lawsuit against the DOE seeking damages based on the DOE's default. The trial on the determination of damages began on July 12 and ended August 31, 2004; a decision is expected in the spring of 2005. None of the Yankee plants have included any allowance for potential recovery of these claims in thei r FERC-filed cost estimates.

The Company's share of Maine Yankee, Connecticut Yankee and Yankee Atomic estimated costs are reflected on the Condensed Consolidated Balance Sheets as regulatory assets or other deferred charges, and nuclear decommissioning liabilities (current and non-current). At September 30, 2004, the Company had regulatory assets of about $6.2 million related to Maine Yankee and $2.3 million related to Connecticut Yankee. These estimated costs are being collected from the Company's customers through existing retail rate tariffs. At September 30, 2004, the Company also had other deferred charges related to incremental dismantling costs of about $10.5 million for Connecticut Yankee and $7.2 million for Yankee Atomic. The Company will adjust the associated regulatory assets, other deferred charges and nuclear decommissioning liabilities when revised estimates are provided.

Maine Yankee: The Company has a 2 percent ownership interest in Maine Yankee. In October 2003, Maine Yankee filed a FERC rate proceeding with an effective date for new rates no later than January 1, 2004. This filing proposed to extend the cost recovery period to 2010 from 2008, specifically to replenish the spent fuel trust fund amounts previously used for independent spent fuel storage installation and fuel transfer. On July 9, 2004, Maine Yankee filed an Offer of Settlement resolving all issues raised by the FERC Rate Case participants. On September 16, 2004, FERC issued an order approving the settlement, which meets Maine Yankee's projected funding requirements. The settlement became effective October 16, 2004. Since January 1, 2004, Maine Yankee's billings to sponsor companies have been based on its October 2003 FERC filing, subject to refund. Prior to that time, its billings were based on its rate case settlement approved by FERC on June 1, 1999.

Connecticut Yankee: The Company has a 2 percent ownership interest in Connecticut Yankee. Costs currently billed by Connecticut Yankee are based on its most recent FERC-approved rates, which became effective September 1, 2000, for collection through 2007. These amounts are being collected from the Company's customers through existing rates.

The Company's estimated aggregate obligation related to Connecticut Yankee is about $12.8 million. The timing, amount and outcome of the Bechtel litigation and FERC rate case filing discussed below cannot be predicted at this time. The Company believes its share of Connecticut Yankee's decommissioning costs is probable of recovery in future rate proceedings.

Page 19 of 45

Bechtel Litigation: Connecticut Yankee is involved in a contract dispute with Bechtel Power Corporation ("Bechtel"), which resulted in termination of the decommissioning services contract between Connecticut Yankee and Bechtel. The lawsuit has been assigned to the Complex Litigation Docket and has been set for a jury trial beginning May 4, 2006. Connecticut Yankee also notified Bechtel's surety of its intention to file a claim under the performance bond.

On June 18, 2004, Bechtel filed a Pre-Judgment Remedy Application ("PJR") requesting a $93 million garnishment of the Decommissioning Trust ("Trust"), Connecticut Yankee shareholder payments to the Trust and any proceeds from the fuel disposal contract litigation pending between Connecticut Yankee and the DOE, as well as attachment of any Connecticut Yankee assets, including the Haddam Neck real property. On July 16, 2004, Connecticut Yankee filed its Objection to the PJR. On July 20, 2004, the Court allowed the Connecticut Department of Public Utility Control ("CT DPUC") to intervene in the PJR proceeding for the limited purpose of objecting to Bechtel's requested garnishment of the Trust and related payments. The Court held hearings on these matters in August and October 2004. On October 29, 2004, Bechtel and Connecticut Yankee entered into an agreement which made additional hearings unnecessary. Bechtel agreed to withdraw its request for an attachment of the Decommiss ioning Trust Fund and related payments, in return for potential attachment of Connecticut Yankee's real property in Connecticut with a book value of $7.9 million and the escrowing of $41.7 million the sponsors are scheduled to pay to Connecticut Yankee through June 30, 2007. This agreement is subject to approval of the Court and would not be implemented until the Court found that such assets were subject to attachment. Connecticut Yankee intends to contest the attachability of such assets. The agreement does not materially change the legal positions in this litigation. The CT DPUC did not object to the agreement.

FERC Rate Case Filing: In December 2003, Connecticut Yankee's Board of Directors endorsed an updated estimate ("2003 Estimate") of the costs for the plant's decommissioning project. This updated estimate reflects 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. The 2003 Estimate of approximately $831.3 million covers the time period 2000 - 2023 and represents an aggregate increase of approximately $395 million in 2003 dollars over the costs estimate in its 2000 FERC rate case settlement, which covered the same time period.

On June 10, 2004, the CT DPUC and the OCC filed a petition ("Petition") with FERC seeking a declaratory order that Connecticut Yankee can recover all decommissioning costs from its sponsor companies, but that those purchasers may not recover in their retail rates any costs that FERC might determine to be imprudently incurred. Connecticut Yankee and its sponsor companies, including the Company, have responded in opposition to the Petition, indicating that the order sought by the CT DPUC would violate the Federal Power Act and decisions of the United States Supreme Court, other federal and state courts, and FERC. The NHPUC filed an intervention notice in support of the Petition. Bechtel has filed an amicus brief and intervention notice in support of the Petition.

On July 1, 2004, Connecticut Yankee filed the 2003 Estimate with the FERC as part of its rate application ("Filing") seeking additional funding to complete the decommissioning project and for storage of spent fuel through 2023. The Filing requested that new rates become effective January 1, 2005. The Filing includes proposed increased decommissioning charges, based on the 2003 Estimate, as well as new annual charges for pension expense and costs of funding post-employment benefits other than pensions. The proposed annual decommissioning collection represents a significant increase in annual charges to the sponsor companies, including the Company, as compared to the existing FERC rates.

On July 6, 2004, FERC issued a notice of the Filing indicating that intervention and protest filings would be due by July 22; however, that date was extended to July 30, at the request of the CT DPUC. Four non-utility interventions have been filed at the FERC by the CT DPUC, the Connecticut Office of Consumer Counsel ("OCC"), Bechtel and the Massachusetts Attorney General. On August 30, 2004, FERC issued an order: 1) accepting for filing the new charges proposed by Connecticut Yankee; 2) suspending these revised charges until February 1, 2005; 3) establishing Administrative Law Judge hearing procedures and schedules; 4) denying the request of the CT DPUC and OCC for both 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 motions to intervene for Bechtel and other applying parties. Connecticut Yankee anticipates that the process of resolving the matters in t he Filing is likely to be contentious and lengthy.

Yankee Atomic: The Company has a 3.5 percent ownership interest in Yankee Atomic. Billings to the Company had ended in July 2000 based on Yankee Atomic's determination that it had collected sufficient funds to complete the decommissioning effort. The Company is not currently collecting Yankee Atomic costs in retail rates.

Page 20 of 45

In April 2003, Yankee Atomic filed with FERC, based on updated cost estimates, for new rates to collect these costs from sponsor companies. FERC approved the resumption of billings starting June 2003 for a recovery period through 2010, subject to refund. On August 6, 2003, Yankee Atomic filed a Settlement Agreement that resolved all issues raised by the parties. Beginning April 2004 and each year following, the new rates are subject to an annual adjustment based on the prior calendar year's data if the decommissioning trust fund market performance is 10 percent greater or 10 percent less than the assumptions used to calculate the schedule of decommissioning charges. As such, a reduction was applied to filed rates beginning with April 2004 billings. The Company expects its share of these costs will be recoverable in future rates. Based on a PSB-approved accounting order, the Company is deferring these costs as a deferred debit.

Millstone Unit #3 The Company has a 1.7303 percent joint-ownership interest in Millstone Unit #3, in which Dominion Nuclear Connecticut, Inc. ("DNC") is the lead owner. The Company has an external trust dedicated to funding its joint ownership share of future decommissioning costs. DNC has suspended contributions to the Millstone Unit #3 Trust Fund because the minimum Nuclear Regulatory Commission ("NRC") funding requirements are being met or exceeded. The Company has also suspended contributions to the Trust Fund, but could choose to renew funding at its own discretion as long as the minimum requirement is met or exceeded. If a need for additional decommissioning funding is necessary, the Company will be obligated to resume contributions to the Trust Fund.

In January 2004, DNC filed, on behalf of itself and the two minority owners, including the Company, a lawsuit against the DOE to seek 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, but the proceedings have been stayed through the end of 2004. At this time, all Millstone Unit #3 spent fuel from the beginning of commercial operations in 1986 resides in the spent fuel pool. There is believed to be adequate spent fuel pool storage capability to support the expected operations through the end of the plants current licensed life in 2025. Currently, the Company is paying 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.

Vermont Yankee In April 2004, in response to an NRC inspection conducted during the Vermont Yankee plant's scheduled refueling outage, 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. According to ENVY, in 1979 the rods were placed in a special stainless steel container in the spent fuel pool. After initial document review and visual inspection of the spent fuel pool, ENVY did not locate the fuel rod segments.

By letter dated May 5, 2004, 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 ENVY's view that costs associated with the spent fuel rod segment inspection effort were the responsibility of VYNPC. By letter dated May 20, 2004, VYNPC responded that based on the information at the time there was no basis for ENVY's claim. Subsequently ENVY's continuing documentation review led to the discovery of the fuel rod segments in a container in the spent fuel pool. The NRC plans to begin its own investigation into ENVY's accounting for these segments. The Company cannot predict the outcome of this matter at this time.

Environmental The Company believes that it is in compliance with all laws and regulations and has implemented procedures and controls to assess and assure compliance. Corrective action is taken when necessary. Below is a brief discussion of known material issues.

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

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

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

In the second quarter of 2004, the Company reached a settlement with one of its insurance carriers. The settlement is reflected in Other Operation on the Condensed Consolidated Income Statement.

At September 30, 2004, a $6.5 million reserve for environmental matters is recorded on the Condensed Consolidated Balance Sheet. At December 31, 2003, the reserve was $7.2 million. The decrease is primarily related to payments made under the settlement with PSNH regarding the Dover site. 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 As part of its windfarm development efforts, in August 2004, Catamount entered into a construction lending arrangement for about $27.3 million for a wind project located in the United States. At September 30, 2004, Catamount advanced $16.5 million for construction of the project. The construction loan will be paid off when the wind project achieves substantial completion and satisfaction of other equity funding conditions. After the construction loan is paid off, Catamount will maintain an equity investment in the wind project.

In November 2004, Catamount entered into an agreement with a third-party developer for the purchase of wind turbines for a joint development project. Upon execution of the agreement, Catamount paid a $1.8 million turbine down payment to the third-party developer. Catamount has the right to terminate the agreement at any time and be released from further obligations under the agreement. In the event of a termination of the turbine supply agreement for the joint development project, the third-party developer or Catamount has up to 18 months from the termination date to utilize the turbines and receive reimbursement of 85 percent of the turbine down payment.

NOTE 12 - SEGMENT REPORTING

The Company's reportable operating segments include: Central Vermont Public Service Corporation ("CV"), which engages in the purchase, production, transmission, distribution and sale of electricity in Vermont; 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 Compa ny's subsidiaries that invest in unregulated business opportunities.

Connecticut Valley's results of operations are reported as discontinued operations and its assets are reported as held for sale in the segment table below. The Company began presenting Connecticut Valley as discontinued operations in the second quarter of 2003. See Note 4 - Discontinued Operations.

Accounting policies of the 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 is as follows (in thousands):

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THREE MONTHS ENDED SEPTEMBER 30
	CV VT	Catamount Energy Corporation	All Other (1)	Discontinued Operations	Reclassification & Consolidating Entries	Consolidated

2004
Revenues from external customers	$72,740	$126	$476	-	$(602)	$72,740
Intersegment revenues	23	-	-	-	(23)	-
Equity income - utility affiliates (2)	410	-	-	-	-	410
Equity income - non-utility affiliates (3)	-	1,145	-	-	(1,145)	-
Income from continuing operations	4,515	1,427	115	-	-	6,057
Income from discontinued operations, net of tax (4)	-	-	-	$8	-	8
Assets held for sale at September 30, 2004 (4)	-	-	-	-	-	-
Total assets at September 30, 2004	483,185	50,037	8,027	-	(6,586)	534,663
2003
Revenues from external customers	$73,839	$118	$477	-	$(595)	$73,839
Intersegment revenues	24	-	-	-	(24)	-
Equity income - utility affiliates (2)	438	-	-	-	-	438
Equity income - non-utility affiliates (3)	-	433	-	-	(433)	-
Income from continuing operations	3,566	855	124	-	-	4,545
Income from discontinued operations, net of tax (4)	-	-	-	$380	-	380
Assets held for sale at December 31, 2003 (4)	-	-	-	9,292	-	9,292
Total assets at December 31, 2003	472,493	48,300	3,874	9,292	(2,640)	531,319

NINE MONTHS ENDED SEPTEMBER 30
	CV VT	Catamount Energy Corporation	All Other (1)	Discontinued Operations	Reclassification & Consolidating Entries	Consolidated

2004
Revenues from external customers	$224,489	$1,375	$1,421	-	$(2,796)	$224,489
Intersegment revenues	69	-	-	-	(69)	-
Equity income - utility affiliates (2)	881	-	-	-	-	881
Equity income - non-utility affiliates (3)	-	3,748	-	-	(3,748)	-
Income from continuing operations	5,180	2,045	340	-	-	7,565
Income from discontinued operations, net of tax (4)	-	-	-	$12,354	-	12,354
Assets held for sale at September 30, 2004 (4)	-	-	-	-	-	-
Total assets at September 30, 2004	483,185	50,037	8,027	-	(6,586)	534,663
2003
Revenues from external customers	$226,903	$309	$1,448	-	$(1,757)	$226,903
Intersegment revenues	74	-	-	-	(74)	-
Equity income - utility affiliates (2)	1,310	-	-	-	-	1,310
Equity income - non-utility affiliates (3)	-	4,579	-	-	(4,579)	-
Income from continuing operations	12,623	951	371	-	-	13,945
Income from discontinued operations, net of tax (4)	-	-	-	$1,034	-	1,034
Assets held for sale at December 31, 2003 (4)	-	-	-	9,292	-	9,292
Total assets at December 31, 2003	472,493	48,300	3,874	9,292	(2,640)	531,319

Includes segments below the quantitative threshold.
See Note 2, Investments in Affiliates.
See Note 3, Non-Utility Investments.
See Note 4, Discontinued Operations.

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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 affect 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:

actions of regulatory bodies, including the pending rate cases before the Vermont Public Service Board,
performance of the Vermont Yankee nuclear power plant,
effects of and changes in weather and economic conditions,
volatility in wholesale power markets,
our ability to maintain our current credit ratings,
performance of our unregulated businesses, and
other considerations such as operations of ISO-New England, changes in the cost or availability of capital, authoritative accounting guidance, and the effect of 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.

COMPANY OVERVIEW

We are a Vermont-based electric utility that transmits, distributes, generates 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. Our wholly owned unregulated subsidiaries include: Catamount Energy Corporation ("Catamount"), which invests in wind energy projects in the United States and United Kingdom; and Eversant Corporation ("Eversant"), which operates a rental water heater business through its subsidiary, SmartEnergy Water Heating Services, Inc.

On January 1, 2004, our wholly owned regulated subsidiary, Connecticut Valley Electric Company, Inc. ("Connecticut Valley"), sold its plant assets and franchise to Public Service Company of New Hampshire ("PSNH"). Prior to the sale, Connecticut Valley distributed and sold electricity in New Hampshire. For accounting purposes, components of the sale transaction are recorded in both continuing and discontinued operations in the consolidated income statement. The gain on the asset sale, net of tax, totaled $12.3 million, but we recorded a loss on power costs, net of tax, of $8.4 million due to termination of the power contract with Connecticut Valley. When the two accounting transactions are combined to assess the total impact of the sale, the result is a gain of $3.9 million recorded in 2004. See discussion of Discontinued Operations below.

The Vermont utility continues to generate sufficient cash flow to support ongoing operations. On July 30, 2004, we refinanced our $75 million of Second Mortgage Bonds, which matured on August 1, 2004, by issuing $75 million of First Mortgage Bonds. While Catamount has sufficient cash flow to cover its operating expenses, additional project investments will require financing or additional funding from us. Catamount is seeking investors and partners to co-invest in the development, ownership and acquisition of other projects. See Liquidity and Capital Resources below for more detail regarding cash flow, investment opportunities and the refinancing.

Vermont regulatory issues remain our top priority. On July 15, 2004, we made two separate filings with the PSB: 1) a cost of service in the PSB's rate investigation; and 2) a request for a 5.01 percent rate increase. We also continue to monitor several State initiatives that could, over time, shift utility regulation away from cost-based regulation. These matters are discussed in more detail below.

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VERMONT RETAIL RATES
Our current retail rates are based on a June 26, 2001 PSB Order approving a settlement with the Vermont Department of Public Service ("DPS"), which provided for, among other things, a 3.95 percent rate increase effective July 1, 2001 and an allowed return on common equity of 11 percent for the year ending June 30, 2002 (capped through January 1, 2004).

In July 2003, we agreed to a Memorandum of Understanding ("MOU") with the DPS regarding our April 2003 costs of service filings that were required based on PSB approval of the Vermont Yankee sale. The MOU concluded that: 1) a rate decrease was not warranted; 2) we would decrease our allowed return on common equity from 11 percent to 10.5 percent effective July 1, 2003; 3) any earnings over the allowed cap of 10.5 percent would be applied to reduce deferred charges on the balance sheet; 4) we would file a fully allocated cost of service plan and a proposed rate redesign; and 5) we would agree to work cooperatively with the DPS to develop and propose an alternative regulation plan.

The PSB issued an Order on January 27, 2004 providing conditional approval for the MOU. It included the following significant modifications: 1) that the allowed return on common equity be reduced to 10.25 percent; 2) starting January 1, 2004 we would begin new amortizations of deferred charges on the balance sheet at December 31, 2003 of about $2.5 million annually; and 3) that we would file with the PSB a proposal to apply the $21 million payment we received in connection with the Connecticut Valley sale to write down deferred charges.

On February 3, 2004, we filed a Request for Reconsideration and Clarification of that Order, and in March 2004 we participated in a workshop to review our filing. On April 7, 2004, the PSB denied our request. While the PSB agreed to remove the third modification, absent our acceptance of the remaining modifications, the PSB concluded that it would open a rate investigation. Consequently, the PSB issued an Order Opening Investigation and Notice of Prehearing Conference in Docket No. 6946 to investigate our current rates.

On July 15, 2004, we filed a cost of service in the rate investigation, which demonstrates a rate deficiency of 2.4 percent, and recommends that rates should not be decreased retroactively to April 1, 2004. Also on July 15, 2004, we filed a request with the PSB for a 5.01 percent rate increase, expected to be effective April 1, 2005, and we requested that the two cases be consolidated.

On September 8, 2004, the PSB consolidated the two cases and confirmed a schedule for proceedings through 2004, with a final order in March 2005.

On October 1, 2004, the DPS filed its testimony with the PSB related to the rate investigation and our request for a rate increase. The DPS's major findings and recommendations include: 1) a rate refund to rate payers retroactive to April 1, 2004 of 4.65 percent or $12 million; and 2) a rate reduction of 5.93 percent or almost $16 million on an annual basis effective with service rendered April 1, 2005.

On October 1, 2004, AARP, an intervener in the case, filed testimony that supports a rate increase of up to 3.5 percent effective April 1, 2005.

Technical Hearings with the PSB were held the week of November 1, 2004. At this time, we cannot predict the outcome of the rate investigation or our request for a 5.01 percent rate increase.

ELECTRIC INDUSTRY RESTRUCTURING
The State of Vermont continues to examine initiatives that are aimed at restructuring the provision of electric service without introducing retail choice. The following discussion highlights initiatives of potential significance.

Renewable Portfolio Standard The possible introduction of a mandatory Renewable Portfolio Standard ("RPS") that could require us to purchase certain amounts of our energy supply requirement from new renewable sources. In 2003 and 2004, several bills were introduced with the Vermont General Assembly that called for the establishment of an RPS requirement. With the adjournment of the Legislative session, it can now be determined that these RPS proposals will not be enacted into law. At this time, we cannot determine whether, or if, a mandatory RPS proposal will be advanced in the next legislative session. However, there remains an interest in the creation of an RPS requirement in the form proposed by the PSB in its 2004 report to the General Assembly.

Renewable Pricing Programs Beginning in 2003, the Vermont General Assembly authorized the establishment of utility-sponsored renewable pricing programs to permit customers to voluntarily elect to either purchase all or part of their electric energy from renewable sources, or cause the purchase and retirement of tradable renewable energy credits on the participating customer's behalf. In either case, the purpose of such pricing programs is to increase the

Page 25 of 45

utility's reliance on renewable sources of energy beyond those the utility would otherwise be required to provide in accordance with its Integrated Resource Plan as approved by the PSB. On March 8, 2004, we filed our proposed renewable pricing program with the PSB, and that program was approved by PSB Order, Docket No. 6933, issued July 30, 2004. Our Voluntary Renewable Pricing Program is called "CVPS Cow Power" and was made available to customers for energy use starting September 1, 2004. The program is priced in the form of a premium relative to the tariff that would otherwise apply. The premium is cost-based so that it reasonably reflects the difference between acquiring the renewable energy and our alternative cost of power. The program also requires that any costs of power in excess of our alternative cost of power will be borne solely by those customers who elect to participate in the renewable pricing program.

Alternative Forms of Regulation Beginning in 2003, the Vermont General Assembly authorized alternative forms of regulation for electric utilities that, besides other criteria, establish a reasonably balanced system of risks and rewards that encourages the utility to operate as efficiently as possible. The PSB may approve an alternative regulation plan only if it finds that the plan will not adversely affect our eligibility for rate-regulated accounting in accordance with accounting principles generally accepted in the United States of America ("GAAP") and reasonably preserves the availability of equity and debt capital resources to us on favorable terms and conditions. At this time, we have not sought authorization to implement an alternate form of regulation for utility activities.

Vermont Hydro-electric Power Authority The creation of a Vermont Hydro-electric Power Authority ("Authority") that will have authority to finance, purchase, own, operate, or manage any interest in the hydroelectric power facilities along the Connecticut and Deerfield Rivers located in Vermont, New Hampshire and Massachusetts, and to sell the electric energy under the control of the authority from those facilities at wholesale to authorized wholesale purchasers. In 2004, the Vermont General Assembly authorized the creation of the Authority. At this time, it cannot be determined whether or when the Authority will be able to acquire an interest in these hydroelectric power facilities.

RISK FACTORS
Regulatory Risk We believe the Company currently complies with the provisions of 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 businesses. If we determine that the Company no longer meets the criteria under SFAS No. 71, the accounting impact would be an extraordinary charge to operations of about $40.7 million on a pre-tax basis as of September 30, 2004, assuming no stranded cost recovery would be allowed through a rate mechanism.

If retail competition is 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 Vermont Yankee Nuclear Power Corporation ("VYNPC"). These contracts support the majority of our total annual energy (mWh) purchases. Our exposure to market price volatility is limited for power supply purchases given that our long-term power forecast reflects energy amounts in excess of that required to meet load requirements. However, if one or both of these sources becomes unavailable for an extended period of time we would be subject to wholesale power price volatility and that amount could be material. Additionally, we rely on the sale of our excess power to help mitigate overall net power costs. The volatility of wholesale power market prices can affect these mitigation efforts.

Interest Rate Risk We have $16.3 million of Industrial Development/Pollution Control bonds outstanding as of September 30, 2004; of that amount $10.8 million has an interest rate that floats monthly with the short-term credit markets and $5.5 million that floats every five years with comparable credit markets. All other utility debt has a fixed rate. There are no interest lock or swap agreements in place.

Interest rate changes could also affect calculations related to estimated pension and other benefit liabilities, which could potentially require contributions to the trusts.

Equity Market Risk At September 30, 2004, our pension trust held marketable equity securities in the amount of $40.9 million and our Millstone Unit #3 decommissioning trust held marketable equity securities of $3.2 million. We also maintain a variety of insurance policies in a Rabbi Trust with a current value of $5.7 million to support various supplemental retirement and deferred compensation plans. The current values of certain policies are affected by changes in the equity market.

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Unregulated Business Catamount is wholly focused on the development, ownership and asset management of wind energy projects. Catamount's future success is dependent on the continued acceptance of wind power as an energy source by large producers, utilities, and other purchasers of electricity. In addition, there is no guarantee of continued wind power acceptance by potential customers as an energy source.

Catamount will require additional capital to pursue its business plan. Catamount is seeking investors and partners to co-invest in the development, ownership and acquisition of projects. There can be no assurance that Catamount will be successful in securing co-investors or obtaining additional funding from us.

DISCONTINUED OPERATIONS

As a condition of the sale, Connecticut Valley paid the Company $21 million to terminate its long-term power contract. In the first quarter of 2004, in accordance with SFAS No. 5, Accounting for Contingencies ("SFAS No. 5"), we recorded a $14.4 million pre-tax loss accrual related to termination of the power contract. The loss accrual represents management's best estimate of the difference between expected future sales revenue, in the wholesale market, for the purchased power that was formerly sold to Connecticut Valley and the cost of purchased power to be incurred to realize those future sales. As required by GAAP, the loss accrual will be reversed and amortized on a straight-line basis through 2015, which represents the estimated life of our power contracts that were in place to supply power to Connecticut Valley.

For accounting purposes, components of the sale transaction are recorded in both continuing and discontinued operations in the consolidated income statement. In addition to the gain on the asset sale, described above, we recorded a loss on power costs, net of tax, of $8.4 million relating to termination of the power contract with Connecticut Valley. When the two accounting transactions are combined to assess the total impact of the sale, the result is a gain of $3.9 million recorded in 2004.

In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, Connecticut Valley is presented as discontinued operations, and 2003 results have been restated. Summarized results of operations of the discontinued operations are as follows (in thousands):

Three Months Ended
September 30

Nine Months Ended
September 30

    2004

     2003

    2004

     2003

Operating revenues

-

$4,951

$24

$14,754

Operating expenses

   Purchased power

-

3,741

-

11,137

   Other operating (income) expenses

$(3)

465

40

1,484

   Income tax expense (benefit)

1

   305

      (14)

     884

   Total operating (income) expenses

(2)

4,511

        26

13,505

Operating income (loss)

2

440

(2)

1,249

Other (expense) income, net

  -

   (60)

        22

   (215)

Net income, net of tax

2

380

20

1,034

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

6

       -

12,334

         -

Income from discontinued operations, net of tax

$8

$380

$12,354

$1,034

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The major classes of Connecticut Valley's assets and liabilities reported as discontinued operations on the Condensed Consolidated Balance Sheets are as follows (in thousands):

September 30

December 31

      2004

      2003

Assets

         Net utility plant

$    -

$9,251

         Other current assets

      -

       41

         Total assets of discontinued operations

$    -

$9,292

Liabilities

         Accounts payable

$     -

$1,749

         Short-term debt (a)

       -

  3,750

         Total liabilities of discontinued operations

$     -

$5,499

(a) Related to a Note Payable due to us that was paid on January 1, 2004.

FERC Exit Fee Proceedings The January 1, 2004 termination of the wholesale power contract between the Company and Connecticut Valley resolved our FERC litigation related to a February 1997 New Hampshire Public Utilities Commission ("NHPUC") Order in which it told Connecticut Valley to stop buying power from the Company.

LIQUIDITY AND CAPITAL RESOURCES

At September 30, 2004, we had cash and cash equivalents of $38 million and working capital of $69.9 million. In the first nine months of 2004, cash and cash equivalents decreased $20.2 million, reflecting net cash provided by operating activities of $23.2 million. Net cash used by investing activities amounted to $62.9 million mostly for investments in available for sale securities and construction expenditures. Net cash used in financing activities was $10.6 million, related to dividends paid on common and preferred stock and retirement of long-term debt. Cash provided by discontinued operations amounted to about $30.1 million, related to cash proceeds from the Connecticut Valley sale.

In the first quarter of 2004, we invested proceeds received from the Connecticut Valley sale and other cash on hand, in available for sale securities with various maturities. At September 30, 2004, these investments included $13.2 million with maturities up to one year, and $22.1 million with maturities greater than one year.

We are currently considering investment alternatives. We intend to invest additional funds in Vermont Electric Power Corporation, Inc.'s ("VELCO") planned transmission upgrades that will contribute toward increasing VELCO's common equity from about 10 percent of its total capitalization to about 25 percent. Construction is scheduled to begin in early 2005 and will extend through 2007. On August 17, 2004, FERC approved our joint filing with Green Mountain Power Corporation ("GMP") for authorization to purchase stock to be issued by VELCO in 2004 and 2005 in connection with financing its planned transmission upgrades. We intend to invest about $7 million in November 2004 and about $5.7 million in the latter part of 2005. In order to finance all of the proposed transmission upgrades, VELCO may require additional equity capital beyond 2005. If so, we would have the opportunity to invest a total of about $25 to $30 million through 2008.

Catamount has sufficient cash flow to cover its ongoing operating expenses, but additional project investments will require financing or additional funding from us. Catamount is also seeking investors and partners to co-invest in the development, ownership and acquisition of projects.

We believe that cash on hand and cash flow from operations will be sufficient to fund our business for the foreseeable future. Material risks to cash flow from operations include: loss of retail sales revenue from unusual weather; slower-than-anticipated load growth and unfavorable economic conditions; and increases in net power costs largely due to lower-than-anticipated margins on sales revenue from excess power.

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Contractual Obligations and Financing
Our significant contractual obligations as of September 30, 2004 are summarized in the table below.

Contractual Obligations

Payments Due by Period (in millions)

Total

Less than 1
      year (a)

1 to 3 years

3 to 5 years

More than 5       years

Long-term Debt - utility

$126.8

-

-

$3.0

$123.8

Interest on Long-term Debt - utility

116.4

$1.8

$14.6

14.6

85.4

Redeemable Preferred Stock

8.0

-

2.0

2.0

4.0

Purchased Power Contracts (b)

1,347.9

36.8

279.2

281.9

750.0

Capital Lease

       11.0

    0.3

      2.2

      1.8

      6.7

   Total Contractual Obligations

$1,610.1

$38.9

$298.0

$303.3

$969.9

(a) Includes payments due during the remainder of the current fiscal year.
(b) Includes power contract commitments with Hydro-Quebec, VYNPC and various independent power producers. See Power Supply Matters below for more information related to these contracts.

Utility During the second quarter of 2004, we received regulatory approvals and waivers needed to issue First Mortgage Bonds to refinance and replace the $75 million of Second Mortgage Bonds that matured on August 1, 2004. On May 28, 2004, we priced such First Mortgage Bonds. Pursuant to such pricing, on July 30, 2004, we issued $20 million of 5 percent First Mortgage Bonds, due in 2011, and $55 million of 5.72 percent First Mortgage Bonds, due in 2019. The proceeds were used to repay in full our $75 million of 8.125 percent Second Mortgage Bonds. The refinancing and lower interest rates will reduce annual interest expense by about $2 million on a pre-tax basis.

We extended $16.9 million of unsecured letters of credit to November 30, 2005. These letters of credit support three series of Industrial Development/Pollution Control Bonds, totaling $16.3 million.

Non-Utility In January 2004, Catamount paid off a $2.5 million balance on its term loan, and in February 2004, Catamount notified the lender of its intent to terminate the credit facility. Effective May 16, 2004, the credit facility was officially terminated. Catamount's office building mortgage matured on April 15, 2004, and Catamount paid the outstanding balance in full.

Catamount solicits, as needed, proposals from selected financial institutions for corporate and/or development credit facilities that will meet its business needs. Catamount cannot predict whether it will be able to ultimately enter into an appropriately priced corporate and/or development credit facility.

As part of its windfarm development efforts, in August 2004, Catamount entered into a construction lending arrangement for about $27.3 million for a wind project located in the United States. At September 30, 2004, Catamount advanced $16.5 million for construction of the project. The construction loan will be paid off when the wind project achieves substantial completion and satisfaction of other equity funding conditions. After the construction loan is paid off, Catamount will maintain an equity investment in the wind project.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our financial statements are prepared in accordance with 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

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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, discontinued operations, unregulated business, revenues, income taxes, decommissioning cost estimates, pension and postretirement benefits. The following is an update to the 2003 Form 10-K:

Regulation If we determine that the Company no longer meets the criteria under SFAS No. 71, the accounting impact would be an extraordinary charge to operations of about $40.7 million on a pre-tax basis as of September 30, 2004, assuming no stranded cost recovery would be allowed through a rate mechanism. Based on a current evaluation of the factors and conditions expected to affect future cost recovery, we believe future recovery of our regulatory assets in the State of Vermont for our retail and wholesale businesses is probable.

Pension and Postretirement Benefits We record pension and other postretirement benefit costs in accordance with SFAS No. 87, Employers' Accounting for Pensions, and SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions. Under these accounting standards, assumptions are made regarding the valuation of benefit obligations and performance of plan assets. Delayed recognition of differences between actual results and those assumed is a required principle of these standards. This approach allows for systematic recognition of changes in benefit obligations and plan performance over the working lives of the employees who benefit under the plans. The following is a list of the primary assumptions, which are updated at the end of each year, for a September 30 measurement date.

Discount Rate - The discount rate is used to record the value of benefits, which are based on future projections, in terms of today's dollars. As of September 30, 2003, the discount rate was decreased from 6.5 percent to 6 percent, in light of long-term interest rates remaining at historically low levels.

Expected Return on Plan Assets ("ROA") - We project the future ROA based principally on historical returns by asset category and expectations for future returns, in part on simulated capital market performance over the next 10 years. The projected future value of assets reduces the benefit obligation a company will record. At September 30, 2002, the ROA changed from 8.5 percent to 8.25 percent. This rate was used to determine the annual expense for 2003 and the same rate was used to determine the 2004 expense.

Rate of Compensation Increase - We project employees' annual pay increases, which are used to project employees' pension benefits at retirement. As of September 30, 2003, the rate of compensation increase was changed from 4 percent to 3.75 percent based on lower than previously projected trends in cost-of-living increases.

Health Care Cost Trend - We project expected increases in the cost of health care. For measurement purposes, we assumed a 12 percent annual rate of increase in the per capita cost of covered health care benefits for pre-65 claims, and an 11.5 percent increase for post-65 claims, for fiscal 2004. These assumptions were based on expected higher health care costs.

Amortization of Gains/(Losses) - We can select the method by which gains or losses are recognized in financial results. These gains or losses are created when actual results differ from estimated results based on the above assumptions. We recognize these gains and losses ratably over a five-year period.

Pension costs totaled $0.8 million for the third quarter and $2.4 million for the first nine months of 2004. Of these amounts, $0.7 million is reflected in results of operations for the third quarter and $2 million for the first nine months, with the remaining amounts capitalized. This compares to pension costs of $0.6 million for the third quarter and $1.9 million for the first nine months of 2003. Of these amounts, $0.5 million is reflected in results of operations for the third quarter and $1.6 million for the first nine months, with the remaining amounts capitalized.

Pension costs and cash funding requirements are expected to increase in future years. At September 30, 2004, the market value of pension plan trust assets was $61.5 million, including $40.9 million in marketable equity securities, $20.3 million in debt securities and $0.3 million in cash and accrued income. At December 31, 2003, pension plan trust assets were $61.3 million, including $42.5 million in marketable equity securities and $18.8 million in debt securities.

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

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accrual represents our best estimate of the difference between expected future sales revenue, in the wholesale market, for the purchased power that was formerly sold to Connecticut Valley and the cost of purchased power to be incurred to realize those future sales. The estimated life of our power contracts that were in place to supply power to Connecticut Valley extend through 2015.

The loss accrual was estimated based on significant variables including assumptions about future power prices, the reallocation of power from the state-appointed purchasing agent ("VEPPI") and future load growth. We will review this estimate at the end of each reporting period, and will increase the reserve if the revised estimate exceeds the recorded loss accrual. Additionally, the loss accrual will be reversed and amortized on a straight-line basis through 2015, as required by GAAP. This amounted to $0.9 million for the nine months ended September 30, 2004.

RESULTS OF OPERATIONS
The following sections of Management's Discussion and Analysis compare the results of operations for the third quarter and first nine months of 2004 with the same periods in 2003 and should be read in conjunction with the condensed consolidated financial statements and accompanying notes included elsewhere in this report.

Consolidated Summary:
Consolidated third quarter earnings were $6.1 million, or 48 cents per basic and 47 cents per diluted share of common stock. Earnings for the third quarter of 2003 totaled $4.9 million, or 39 cents per basic and 38 cents per diluted share of common stock.

For the first nine months of 2004, we reported earnings of $19.9 million, or $1.58 per basic and $1.56 per diluted share of common stock. Earnings for the first nine months of 2003 totaled $15 million, or $1.19 per basic and $1.17 per diluted share of common stock.

Both core utility operations and Catamount contributed positively to third quarter earnings. At the utility, purchased power costs were lower compared to the same period in 2003 due in large part to increased megawatt hours available to serve customers, or for resale, due to the termination of the power contract with Connecticut Valley. Operating costs remained in line with 2003 due to continued efforts to streamline work processes in all areas of the utility. We are also beginning to benefit from lower interest expense due to second mortgage bond refinancing in August. Catamount continues to take advantage of opportunities to sell projects from its existing portfolio while developing its wind energy business.

The following tables provide a reconciliation of 2004 and 2003 diluted earnings per share.

Third quarter 2004 vs. third quarter 2003:

2003 Earnings per diluted share

$.38

Year over Year Effects on Earnings:

Lower purchased power costs

.07

Higher resale sales

.06

Catamount - higher earnings

.05

Other

.03

Higher other operating revenue

.03

Lower retail and firm sales

(.02)

RS-2 power contract termination

(.13)

Subtotal

.09

$.47

2004 Earnings per diluted share

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First nine months 2004 vs. first nine months 2003:

2003 Earnings per diluted share

$1.17

Year over Year Effects on Earnings:

Higher retail and firm sales

.11

IRS tax settlement received in the second quarter of 2004

.09

Catamount higher earnings

.09

Higher resale sales

.08

Higher other operating revenue

.07

Other

.07

Lower purchase power costs - excluding SFAS No. 5 loss accrual

.03

Discontinued operations - 2003

(.09)

RS-2 power contract termination

(.38)

      Subtotal

.07

Net impact of CVEC sale:

  Gain on discontinued operations

1.01

  SFAS No. 5 loss accrual - termination of power contract

(.69)

      Subtotal

.32

2004 Earnings per diluted share

$1.56

CONDENSED CONSOLIDATED INCOME STATEMENT DISCUSSION
The following includes a more detailed discussion of the components of our Condensed Consolidated Income Statements and related year-over-year variances.

Operating revenues: The majority of our operating revenues are generated through retail sales from the regulated Vermont utility business. Other resale sales are related to the sale of excess power from our owned and purchased power supply portfolio. Operating revenues and related mWh sales for the three and nine months ended September 2004 and 2003 are summarized below:

	Three Months Ended September 30				Nine Months Ended September 30
	mWh Sales		Revenues (000's)		mWh Sales		Revenues (000's)
	2004	2003	2004	2003	2004	2003	2004	2003
Retail sales:
Residential	220,046	225,960	$29,780	$30,433	711,303	707,578	$94,093	$93,384
Commercial	223,078	221,121	26,902	26,721	639,071	631,155	77,057	76,088
Industrial	100,588	96,030	7,946	7,855	307,986	290,422	25,331	24,662
Other retail	1,366	1,368	407	406	4,075	4,063	1,208	1,204
Total retail sales	545,078	544,479	65,035	65,415	1,662,435	1,633,218	197,689	195,338
Resale sales:
Firm (1)	994	1,236	47	47	3,371	3,886	210	137
RS-2 power contract (2)	-	32,852	-	2,764	-	93,337	-	8,079
Other	136,944	98,549	5,701	4,382	414,692	404,850	20,347	18,629
Total resale sales	137,938	132,637	5,748	7,193	418,063	502,073	20,557	26,845
Other revenues	-	-	1,957	1,231	-	-	6,243	4,720
Total	683,016	677,116	$72,740	$73,839	2,080,498	2,135,291	$224,489	$226,903

Based on FERC filed tariffs.

The wholesale power contract between the Company and Connecticut Valley was terminated on January 1, 2004. See Discontinued Operations above.

Operating revenues decreased $1.1 million for the third quarter of 2004 compared to 2003 due to the following factors:

The January 1, 2004 termination of the power contract with Connecticut Valley decreased resale revenue by $2.7 million, but made about 33,000 mWh available for use by the Company or for other resale sales.
Other Resale revenue increased $1.3 million due to higher sales volume, partially offset by lower average market prices for sales to ISO-New England versus contract prices for forward sales in 2003. The increased volume primarily resulted from termination of the Connecticut Valley power contract.

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Retail and firm sales decreased $0.4 million, primarily due to lower residential customer usage, partially offset by higher industrial and commercial usage.
Other operating revenue increased $0.7 million primarily due to increased transmission revenue, and contract service billing including mutual aid work in Florida.

Operating revenues decreased $2.4 million for the first nine months of 2004 compared to 2003 due to the following factors:

The January 1, 2004 termination of the power contract with Connecticut Valley decreased resale revenue by $8 million, but made about 93,000 mWh available for use by the Company or for other resale sales.
Other Resale revenue increased $1.7 million due to higher average market prices and higher sales volume. The increased volume resulted from termination of the Connecticut Valley power contract, partially offset by fewer mWh available for resale as a result of scheduled nuclear plant outages at Vermont Yankee and Millstone Unit #3 in the second quarter of 2004, and a 19-day unscheduled outage at the Vermont Yankee plant that ended July 7, 2004.
Retail and firm sales increased $2.4 million due to a 1.8 percent increase in volume related to colder weather in the first quarter of 2004 and higher industrial customer usage.
Other operating revenue increased $1.5 million due to higher pole attachment revenue, transmission revenue and contract service billing, including mutual aid work in Florida.

Purchased Power: The cost components of purchased power for the three and nine months ended September 2004 and 2003 are summarized below. Also see Power Supply Matters below for a detailed discussion of our power supply sources, power management, purchased power commitments and nuclear investments.

Three Months Ended September 30

(dollars in thousands)

2004

2003

mWh

Amount

mWh

Amount

  Energy

619,446

$25,762

646,256

$26,456

  Capacity:

     Capacity purchases

9,865

10,641

     SFAS No. 5 loss accrual

            -

            -

Total purchased power

$35,627

$37,097

Nine Months Ended September 30

(dollars in thousands)

2004

2003

mWh

Amount

mWh

Amount

  Energy

1,892,660

$83,305

1,972,957

$82,830

  Capacity:

     Capacity purchases

30,258

31,299

     SFAS No. 5 loss accrual

    14,351

              -

Total purchased power

$127,914

$114,129

Purchased power expense decreased $1.5 million in the third quarter of 2004 compared to 2003 as a result of the following factors:

Short-term purchases, including purchases from ISO-New England, decreased $1.4 million due to termination of the Connecticut Valley power contract which made more mWh available to support customer usage.
Purchases under long-term power contracts increased $0.2 million, mostly due to higher output from Independent Power Producers, offset by lower Vermont Yankee capacity costs and fewer purchases due to an unscheduled outage at the plant which impacted the first 7 days of July.
Other purchased power costs decreased $0.3 million due to monthly reversals of the loss accrual related to termination of the Connecticut Valley power contract described below.

Purchased power expense increased $13.8 million for the first nine months of 2004 compared to 2003 as a result of the following factors:

In the first quarter of 2004, in accordance with SFAS No. 5, we recorded a $14.4 million pre-tax loss accrual related to termination of the power contract with Connecticut Valley. The loss accrual represents management's best estimate of the difference between expected future sales revenue, in the wholesale market, for the purchased power that was formerly sold to Connecticut Valley and the cost of purchased power to be incurred to realize those future

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sales. In accordance with GAAP, the loss accrual will be reversed and amortized on a straight-line basis through 2015, which represents the estimated life of our power contracts that were in place to source the Connecticut Valley power contract. Such amortizations amounted to $0.9 million in the first nine months of 2004 and are included as a reduction in capacity costs.
Short-term purchases increased $6.5 million due to purchases of replacement energy for nuclear plant outages in the second quarter of 2004 and higher market prices for purchases versus market prices for the same period in 2003, partially offset by 2004 deferrals of incremental replacement energy costs related to the Millstone Unit #3 refueling outage the Vermont Yankee unscheduled outage.
Purchases under long-term power contracts decreased $6.3 million due to second quarter 2004 Vermont Yankee outages including a scheduled refueling outage and a 19-day unscheduled outage, and fewer Hydro-Quebec deliveries, partially offset by higher output from Independent Power Producers.
Other purchased power costs increased $0.1 million.

Operating Expenses: Operating expenses represent costs incurred to support our core business, excluding purchased power expense, which is described above. The year-over-year variances for the third quarter and first nine months of 2004 versus the same periods in 2003 are described below.

Production and Transmission These are expenses associated with generating electricity from our wholly and jointly owned units and transmission of electricity. The decrease for the first nine months of 2004 is primarily due to lower output from our jointly owned units and lower transmission costs.

Other operation These expenses are primarily related to operating activities such as customer accounting, customer service, administrative and general, and other operating costs incurred to support our core business. These expenses increased for the third quarter and first nine months of 2004. Factors affecting the increase included higher pole attachment expenses, higher employee-related costs (pension and medical), and higher bad debt expense related to a second quarter 2004 customer bankruptcy, offset by the favorable impact of an insurance settlement received in the second quarter of 2004. Also, conservation and load management amortizations in 2003 were $0.3 million in the third quarter and $1.4 million in the first nine months versus a minimal amount in 2004.

Maintenance These expenses are primarily related to costs associated with maintaining our electric distribution system such as tree trimming and maintenance of overhead lines. Costs decreased for the third quarter due to lower service restoration, partially offset by higher pole treating expenses. The increase in costs for the first nine months of 2004 is mostly related to increased tree trimming and pole treating costs.

Depreciation We use the straight-line remaining-life method of depreciation. There was no significant variance for 2004 versus 2003.

Other taxes, principally property taxes This is primarily related to property taxes and payroll taxes. There was no significant variance for 2004 versus 2003.

Taxes on Income Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences and changes in valuation allowances for the periods. 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, which reduced regulatory tax assets by about $1 million, and increased state income tax expense.

For the first nine months of 2004, taxes on income included a $5.5 million benefit related to the loss accrual resulting from the termination of the power contract with Connecticut Valley, as described in Discontinued Operations above. In the second quarter of 2004, we received $1.8 million from an income tax settlement related to an appeal for a refund of an overpayment from a prior audit. The proceeds included federal income tax of $0.5 million, interest expense of $0.4 million and $0.9 million of interest income. See Income Tax Matters below.

Equity in earnings of affiliates: These are related to our equity investments such as VELCO and VYNPC. The decrease for the third quarter and first nine months of 2004 is primarily related to lower VYNPC interest income due to delayed distribution of sale proceeds in 2003.

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Gain on sale of non-utility investments: In the third quarter of 2004, Catamount completed its sale of Glenns Ferry and Rupert investments and the sale of its Fibrothetford note receivable and equity investment. See Diversification below.

Other income, net: These income items, net of deductions, are related to the non-operating activities of the utility business and operating activities of our unregulated businesses. The increase of $1.5 million for the third quarter and $2.8 million for the first nine months of 2004 is explained in the table below (dollars in millions):

2004 vs. 2003

Third Quarter

Year to date

        Utility Business

          IRS tax settlement

-

$0.9

          Interest income

$0.2

0.7

          Cash surrender value of life insurance policies

-

(0.1)

          Carrying costs on regulatory assets

-

(0.2)

          Other

(0.2)

(0.6)

        Unregulated Businesses

          Catamount, excluding gain on sale of investments

  1.5

  2.1

Total Variance

$1.5

$2.8

Utility Business The IRS tax settlement is described in Taxes on Income above. Interest income increased due to additional investments in available for sale securities. The cash surrender value of certain life insurance policies decreased due to financial market results, offset by death benefit proceeds received in 2004. Other items include various deductions, miscellaneous revenue, and adjustments.

Unregulated Businesses Catamount's net revenues increased for the third quarter and first nine months of 2004, mainly due to fees associated with Catamount's United Kingdom development efforts. Other factors affecting Catamount's net revenues for the third quarter and first nine months of 2004 included lower earnings from certain of its equity investments, offset by lower operating costs. See Diversification below.

Provision for income taxes: Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences and changes in valuation allowances for the periods. The increase for the third quarter and first nine months of 2004 is primarily due to higher Catamount earnings related to the sales of investment interests. Also in the third quarter of 2003 there was a $2.3 million reduction in income tax valuation allowances associated with previously recorded equity losses from asset impairments. In 2003, the consolidated federal income tax provision reflected a benefit due to realization of capital gains on the CVEC sale, which afforded Catamount the opportunity to reduce tax valuation allowances.

Interest on long-term debt: Interest expense on long-term debt includes the utility business and our unregulated businesses. The decrease for the third quarter and first nine months of 2004 is primarily related to lower utility long-term debt and lower interest rates resulting from the second mortgage bond refinancing which is described in more detail in Contractual Obligations and Financing above. Catamount also had lower long-term debt resulting in lower interest expense.

Other interest expense: Other interest expense includes the utility business and our unregulated businesses. The increase for the third quarter is related to higher carrying costs on regulatory liabilities. The decrease in the first nine months of 2004 is related to an IRS tax settlement, described above, partially offset by increased carrying costs on regulatory liabilities.

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

POWER SUPPLY MATTERS

Sources of Energy We purchase about 90 percent of our power 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 Supply Management In order to balance hourly load and supply, we engage in short-term purchases and sales in the wholesale markets administered by the New England Independent System Operator ("ISO-New England") and with other third parties, primarily in New England, to minimize net power costs and risks to our customers. On an hourly basis, power is sold or bought through ISO-New England to balance our resource output and load requirements. From time to time, we also enter into forward sale or purchase transactions to reduce volatility of our forecasted power costs. For the period January

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through March 2004, we sold 148,400 mWh through a forward sale contract. We also entered into a forward purchase contract for about 71,900 mWh for April 2004 for replacement power during Vermont Yankee's scheduled refueling outage, and used short-term forward purchase transactions during Vermont Yankee's 19-day unscheduled outage that began on June 18. These forward transactions supplement the hourly purchases and sales with ISO-New England.

We continue to monitor, and adapt to, changes in New England wholesale power markets and open access transmission systems, including Standard Market Design and the move to regional transmission organizations. Below is a brief discussion of both.

Standard Market Design ("SMD")

In March 2003, ISO-New England implemented SMD, a significant step to restructuring the competitive wholesale energy markets in the Northeast. SMD has affected wholesale power prices related to short-term sales and purchases as well as the costs of our own generation.

On May 1, 2004, we began to settle our power accounts with ISO-New England on a stand-alone (direct) basis. Previously, we and other Vermont distribution utilities were settled at the ISO-New England as a single entity through VELCO, in which VELCO received the ISO-New England's monthly settlement invoice and performed the sub-settlements within Vermont. With changes in power markets, and New England Power Pool ("NEPOOL") and ISO-New England rules and procedures, many of the former benefits of a single Vermont settlement no longer exist. Direct settlement now provides us with flexibility, cost savings and efficiency.

Transmission plays a significant role in the competitive wholesale market. At this time, much of the cost of New England's existing and new high-voltage transmission system (115 kV looped facilities) is shared by all New England utilities. VELCO is planning several significant upgrades, which have been approved by NEPOOL for shared cost treatment. Vermont has traditionally had higher-than-average transmission costs. The new 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. We will pay a share of such projects elsewhere in New England, but the net economic effect is expected to be beneficial. Also, better reliability elsewhere in the region benefits Vermont's reliability because of the highly integrated nature of New England's high-voltage network. If other future transmission facilities do not qualify for cost sharing, those costs will be charged only to the requesting entity and our share of such costs will be affected by FERC approved cost-allocation rules contained in VELCO's and our tariffs and agreements.

Regional Transmission Organizations ("RTOs")
On October 31, 2003, ISO-New England and the transmission-owning entities in New England, including us, filed a joint proposal with FERC to create an RTO for New England. That filing received conditional approval from the FERC and the RTO parties have reached agreement in principle to resolve certain outstanding issues with NEPOOL. The RTO parties have requested that FERC expedite its decision processes on remaining issues, in particular, the rate of return that will be permitted on transmission investment.

Certain transmission owners in New England also reached an agreement to submit (no later than the RTO operational date) a tariff, agreements and other documents to FERC to include costs, in the region-wide rate for transmission service, associated with certain transmission facilities, commonly referred to as the Highgate Facilities. We have agreed to defer the FERC filing to allow time for the RTO stakeholders' review process, and expect to file the changes that have been agreed to shortly after this process is concluded. Although we expect that the RTO will affect our transmission costs, we cannot predict the nature of that effect at this time.

Power Contract Commitments
Hydro-Quebec We purchase varying amounts of power from Hydro-Quebec under the Vermont Joint Owners ("VJO") Power Contract and related contracts negotiated between us and Hydro-Quebec, which extend through 2016. There are specific contractual provisions that provide that in the event any VJO member fails to meet its 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 existing contracts with Hydro-Quebec, we purchased $14.1 million of energy and related capacity in the third quarter and $42.6 million in the first nine months of 2004 compared to $14.2 million and $43.2 million for the same periods in 2003.

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On January 30, 2004, Hydro-Quebec notified the VJO that it is not likely that it will reschedule deliveries of energy not delivered due to interconnection deficiencies during the present and prior contract years. We are working with Hydro-Quebec, and have since that time minimized such interconnection deficiencies through scheduling changes and use of interconnection facilities. Any reduced deliveries would likely increase net power costs due to additional short-term energy purchases, or decreased resale sales, but would not affect capacity costs.

By letter dated June 25, 2004, Hydro-Quebec notified the VJO that it would exercise its option to reduce the annual capacity factor for energy received under the contract from 75 percent to 65 percent for the contract year beginning November 1, 2004. We anticipated that Hydro-Quebec would make this election and determined that our remaining energy supplies are sufficient to meet expected loads. Under the terms of the contract, this election exhausts Hydro-Quebec's preset number of options to reduce the annual capacity factor, so we do not anticipate similar reductions in the future, unless the VJO elects them.

Vermont Yankee 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 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 any energy to VYNPC when the plant is not operating. Total purchases, primarily energy-related, amounted to $15.4 million in the third quarter and $41.6 million in the first nine months of 2004, as compared to $16.3 million and $50 million for the same periods in 2003.

In 2003, ENVY sought PSB approval to increase generation at the Vermont Yankee plant by approximately 20 percent, or 110 megawatts. On November 5, 2003, the DPS announced that it had agreed to support ENVY's proposed uprate, including ENVY's agreement to provide outage protection indemnification, Ratepayer Protection Proposal ("RPP"), for us and GMP in case the uprate causes temporary reductions in output that would require the purchase of higher-cost replacement power. The outage protection coverage will be in place for three years, and under the RPP we have indemnification rights up to about $2.8 million. In early 2004, the PSB approved the uprate subject to certain conditions, including an additional RPP agreement ("Supplemental Ratepayer Protection Proposal") in the event that ENVY must reduce power output or shutdown because of lack of spent fuel storage caused by the uprate or to comply with certain state and federal measured radiation limits.

On February 10, 2004, ENVY notified us that it expected to reduce plant output after the April 2004 scheduled refueling outage, and continuing until ENVY receives Nuclear Regulatory Commission ("NRC") approval for the uprate, which is expected no earlier than November 2004. Vermont Yankee completed its scheduled outage on May 3, 2004, and at that time our 182 MW entitlement was reduced by 7 MW. We expect that the financial effects of such a reduction will be covered under the terms of the RPP.

In April 2004, in response to an NRC inspection conducted during the Vermont Yankee plant's scheduled refueling outage, 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. According to ENVY, in 1979 the rods were placed in a special stainless steel container in the spent fuel pool. After initial document review and visual inspection of the spent fuel pool, ENVY did not locate the fuel rod segments.

By letter dated May 5, 2004, 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 ENVY's view that costs associated with the spent fuel rod segment inspection effort were the responsibility of VYNPC. By letter dated May 20, 2004, VYNPC responded that based on the information at the time there was no basis for ENVY's claim. Subsequently, ENVY's continuing documentation review led to the discovery of the fuel rod segments in a container in the spent fuel pool. The NRC plans to begin its own investigation into ENVY's accounting for these segments. We cannot predict the outcome of this matter at this time.

On June 18, 2004, an incident that resulted in a fire in or around the plant's transformer caused the Vermont Yankee plant to shut down for about 19 days. The NRC is conducting a root-cause investigation of this incident. On July 12, 2004, the PSB approved our request for a preliminary Accounting Order for deferral of incremental replacement power costs incurred as a result of the plant's forced outage. In the second quarter of 2004, based on the preliminary Accounting Order, we deferred about $0.6 million of incremental replacement power costs incurred for the period June 18-30. In the third quarter

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we deferred an additional $0.2 million for the period July 1-9. The PSB's approval included the following two provisions: 1) it did not allow for recovery of carrying costs; and 2) required monthly amortization over a three-year period beginning July 1, 2004. On July 23, 2004, we filed a Motion for Reconsideration and requested an immediate temporary stay related to these provisions. On July 28, 2004, the PSB granted our request and stayed the two provisions until the PSB issues a Final Accounting Order which will be addressed in our pending rate proceeding.

Independent Power Producers ("IPPs") We purchase power from a number of IPPs who own qualifying facilities under the Public Utility Regulatory Policies Act of 1978. These qualifying facilities produce energy using hydroelectric, biomass and refuse-burning generation. The majority of these purchases are made from VEPPI, which purchases and redistributes the power to all Vermont utilities. We purchased energy and related capacity in the amount of $4.2 million in the third quarter and $15.6 million in the first nine months of 2004. This compares to purchases of $3.4 million in the third quarter and $13 million in the first nine months of 2003. For both years, about 90 percent of the purchases were related to VEPPI.

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

Peterson Dam In January 2003, we, the Vermont Agency of Natural Resources ("Agency"), Vermont Natural Resources Council and other parties reached an agreement to allow us to relicense the four dams we own and operate on the Lamoille River. According to the agreement, we will receive a water quality certificate from the State, which is needed for FERC to relicense the facilities for 30 years. The agreement also stipulates that subject to various conditions, we must begin decommissioning Peterson Dam in about 20 years. The agreement requires PSB approval of full rate recovery related to decommissioning the Peterson Dam, including full rate recovery of replacement power costs when the dam is out of service. On July 31, 2003, the Agency published its draft water quality certificate and on October 29, 2003, pursuant to the schedule set forth in the agreement, we filed a petition with the PSB for approval of the rate recovery mechanisms. On April 2, 2004, the PSB issue d an order adopting a schedule that permits a final order in the fourth quarter of 2004. In the second quarter of 2004, at a public hearing, many residents of the Town of Milton opposed the dam's removal. The PSB held two additional public meetings in September 2004, and testimony was given in support of an opposition to removal of the power station. We cannot predict the outcome of this matter.

Nuclear Generating Companies We are responsible for our joint ownership share in Millstone Unit #3 decommissioning costs as described below. We are also 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 four 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. Maine Yankee, Connecticut Yankee and Yankee Atomic are parties to a lawsuit against the DOE seeking damages based on the DOE's default. The trial on the determination of damages began on July 12 and ended August 31, 2004; a decision is expected in the spring of 2005. None of the Yankee plants have included any allowance for potential recovery of these claims in their FERC - -filed cost estimates.

Our share of Maine Yankee, Connecticut Yankee and Yankee Atomic estimated costs are reflected on the Condensed Consolidated Balance Sheets as regulatory assets or other deferred charges, and nuclear decommissioning liabilities (current and non-current). At September 30, 2004, we had regulatory assets of about $6.2 million related to Maine Yankee and $2.3 million related to Connecticut Yankee. These estimated costs are being collected from our customers through existing retail and wholesale rate tariffs. At September 30, 2004, we also had other deferred charges related to incremental dismantling costs of about $10.5 million for Connecticut Yankee and $7.2 million for Yankee Atomic. We will adjust the associated regulatory assets, other deferred charges and nuclear decommissioning liabilities when revised estimates are provided.

Maine Yankee: We have a 2 percent ownership interest in Maine Yankee. In October 2003, Maine Yankee filed a FERC rate proceeding with an effective date for new rates no later than January 1, 2004. This filing proposed to extend the cost recovery period to 2010 from 2008, specifically to replenish the spent fuel trust fund amounts previously used for independent spent fuel storage installation and fuel transfer. On July 9, 2004, Maine Yankee filed an Offer of Settlement resolving all issues raised by the FERC Rate Case participants. On September 16, 2004, FERC issued an order approving the settlement, which meets Maine Yankee's projected funding requirements. The settlement became effective October 16, 2004. Since January 1, 2004, Maine Yankee's billings to sponsor companies have been based on its October 2003 FERC filing, subject to refund. Prior to that time, its billings were based on its rate case settlement approved by FERC on June 1, 1999.

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Connecticut Yankee: We have a 2 percent ownership interest in Connecticut Yankee. Costs currently billed by Connecticut Yankee are based on its most recent FERC-approved rates, which became effective September 1, 2000, for collection through 2007. These amounts are being collected from our customers through existing rates.

Our estimated aggregate obligation related to Connecticut Yankee is about $12.8 million. The timing, amount and outcome of the Bechtel litigation and FERC rate case filing discussed below, cannot be predicted at this time. We believe our share of Connecticut Yankee's decommissioning costs is probable of recovery in future rate proceedings.

Bechtel Litigation: Connecticut Yankee is involved in a contract dispute with Bechtel Power Corporation ("Bechtel"), which resulted in termination of the decommissioning services contract between Connecticut Yankee and Bechtel. The lawsuit has been assigned to the Complex Litigation Docket and has been set for a jury trial beginning May 4, 2006. Connecticut Yankee also notified Bechtel's surety of its intention to file a claim under the performance bond.

On June 10, 2004, the CT DPUC and the OCC filed a petition ("Petition") with FERC seeking a declaratory order that Connecticut Yankee can recover all decommissioning costs from its sponsor companies, but that those purchasers may not recover in their retail rates any costs that FERC might determine to be imprudently incurred. Connecticut Yankee and its sponsor companies, including us, have responded in opposition to the Petition, indicating that the order sought by the CT DPUC would violate the Federal Power Act and decisions of the United States Supreme Court, other federal and state courts, and FERC. The NHPUC filed an intervention notice in support of the Petition. Bechtel has filed an amicus brief and intervention notice in support of the Petition.

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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 motions to intervene for Bechtel and other applying parties. Connecticut Yankee anticipates that the process of resolving the matters in the Filing is likely to be contentious and lengthy.

Yankee Atomic: We have a 3.5 percent ownership interest in Yankee Atomic. Billings from Yankee Atomic ended in July 2000 based on Yankee Atomic's determination that it had collected sufficient funds to complete the decommissioning effort. We are not currently collecting Yankee Atomic costs in rates.

In April 2003, Yankee Atomic filed with FERC, based on updated cost estimates, for new rates to collect these costs from sponsor companies. FERC approved the resumption of billings starting June 2003 for a recovery period through 2010, subject to refund. On August 6, 2003, Yankee Atomic filed a Settlement Agreement that resolved all issues raised by the parties. Beginning April 2004 and each year following, the new rates are subject to an annual adjustment based on the prior calendar year's data if the decommissioning trust fund market performance is 10 percent greater or 10 percent less than the assumptions used to calculate the schedule of decommissioning charges. As such, a reduction was applied to filed rates beginning with April 2004 billings. We expect our share of these costs will be recoverable in future rates. Based on a PSB-approved accounting order, we are deferring these costs.

Millstone Unit #3: We have a 1.7303 percent joint-ownership interest in Millstone Unit #3, in which Dominion Nuclear Connecticut, Inc. ("DNC") is the lead owner. We have an external trust dedicated to funding our joint ownership share of future decommissioning costs. DNC has suspended contributions to the Millstone Unit #3 Trust Fund because the minimum NRC funding requirements are being met or exceeded. We have also suspended contributions to the Trust Fund, but could choose to renew funding at our own discretion as long as the minimum requirement is met or exceeded. If a need for additional decommissioning funding is necessary, we will be obligated to resume contributions to the Trust Fund.

In January 2004, DNC filed, on behalf of itself and the two minority owners, including the Company, a lawsuit against the DOE to seek 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, but the proceedings have been stayed through the end of 2004. At this time, all Millstone Unit #3 spent fuel from the beginning of commercial operations in 1986 resides in the spent fuel pool. There is believed to be adequate spent fuel pool storage capability to support the expected operations through the end of the plants current licensed life in 2025. Currently, we are paying 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.

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

Catamount At September 30, 2004, Catamount had interests in seven operating independent power projects located in Rumford, Maine; East Ryegate, Vermont; Hopewell, Virginia; Nolan County, Texas; Thetford, England; Thuringen, Germany; and Mecklenburg-Vorpommern, Germany.

Catamount is wholly focused on the development, ownership and asset management of wind energy projects. Catamount is seeking investors and partners to co-invest with Catamount in the development, ownership and acquisition of projects, which will be financed by equity and non-recourse debt. Management cannot predict the timing or outcome of potential future asset sales or whether this strategy will be successful.

Catamount has projects under development in the United States and United Kingdom. In July 2003, Catamount established Catamount Cymru Cyf., an English and Welsh private limited company to develop a project located in Wales. 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 of shares 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.

Also see Liquidity and Capital Resources discussion above.

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Catamount Results
Catamount recorded earnings of $1.4 million in the third quarter and $2 million for the nine months ended September 30, 2004, including $1.6 million related to third quarter 2004 gains on sales and associated tax benefits. This compares to earnings of $0.9 million in the third quarter and $1 million for the nine months ended September 30, 2004, including a $2.3 million reduction in income tax valuation allowances associated with previously recorded equity losses resulting from asset impairments. The 2003 reduction in income tax valuation allowances resulted from a benefit in the consolidated federal income tax provision due to management's best estimate that the Company would receive capital gains treatment on the Connecticut Valley sale.

Other factors affecting higher earnings in 2004 versus 2003 include fees, primarily received in the first quarter of 2004, associated with Catamount's United Kingdom development efforts, lower operating costs and lower interest expense on long-term debt. Partially offsetting these increases were lower earnings from certain of Catamount's equity investments, lower interest income on investments, lower gain on foreign currency and higher intangible asset and debt amortizations. Information regarding certain of Catamount's investments follows.

Fibrothetford Limited ("Fibrothetford") In September 2004, Catamount entered into Sales and Purchase Agreements with third parties for the sale of its Fibrothetford notes receivable and equity investments. The note receivable was sold in September 2004, resulting in an after-tax gain of $0.6 million and an additional $0.2 million of income tax benefits associated with the sale.

Eversant At September 30, 2004, Eversant had a $1.4 million investment, representing a 12 percent ownership interest in the Home Service Store, Inc. ("HSS"), which has established a network of affiliate contractors who perform home maintenance repair and improvements for HSS 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 for the first nine months of 2004 and 2003.

INCOME TAX MATTERS
Our income tax expense is based on estimated annual effective tax rates, which differ from the federal statutory rate of 35 percent, primarily due to state and local income taxes, nondeductible expenses, the dividends received deduction, life insurance and other items.

We account for income taxes in accordance with SFAS No. 109, Accounting for Income Taxes ("SFAS No. 109"), requiring recognition of deferred tax assets and liabilities for the future tax effects of temporary differences between carrying amounts and the tax basis of assets and liabilities. Under this method, deferred income taxes result from applying the statutory rates to the differences between the book and tax basis of asset and liabilities. SFAS No. 109 prohibits the recognition of all or a portion of deferred income tax benefits if it is more likely than not that the deferred tax asset will not be realized. Tax effects of temporary differences and tax carryforwards give rise to significant portions of the deferred tax assets and deferred tax liabilities.

For the first nine months of 2004 taxes on income includes a $5.5 million benefit related to the SFAS No. 5 loss accrual as described in Note 4 - Discontinued Operations.

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In the second quarter of 2004, we received $1.8 million from an income tax settlement related to an appeal for a refund of an overpayment from a prior audit for the tax years 1982 through 1984. The proceeds included federal income tax of $0.5 million, interest expense of $0.4 million that was previously paid, and $0.9 million of interest income on the refunds. The settlement, net of legal fees and tax on the interest income, resulted in a $1.1 million favorable effect on 2004 results.

Previously in the third quarter of 2003, Catamount reduced, by $2.3 million, income tax valuation allowances, associated with previously recorded equity losses resulting from asset impairments. This was the result of a benefit in the consolidated federal income tax provision due to our best estimate that we would receive capital gains treatment on the Connecticut Valley sale.

RECENT ACCOUNTING PRONOUNCEMENTS

See Note 1 to the accompanying Condensed Consolidated Financial Statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

See Risk Factors above, included in Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations.

Item 4. Controls and Procedures.

The Company's disclosure controls and procedures are designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission.

Under the direction of the Company's Chief Executive Officer and Chief Financial Officer, Management evaluated the Company's disclosure controls and procedures as defined in Rules 13a - 15(e) or 15d - 15(e) as of September 30, 2004. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that: 1) the Company's disclosure controls and procedures were effective as of September 30, 2004 in timely alerting them to internal information relating 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; and 2) there have been no changes in the Company's internal control over financial reporting that occurred during the quarter ended September 30, 2004, that materially affected, or are reasonably likely to materially affect the Company's 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 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. The Company cannot predict the outcome of the current rate investigation before the Public Service Board. See Note 7 - Retail Rates.
Item 6.		Exhibits.
			List of Exhibits
			A 10.101	Form of Central Vermont Public Service Performance Share Agreement Pursuant to the Performance Share Incentive Plan.
			A 10.102	Form of Central Vermont Public Service Corporation Stock Option Agreement Pursuant to the 2002 Long-Term Incentive Plan.
			A 10.103	Form of Central Vermont Public Service Corporation Stock Option Agreement Pursuant to the 2000 Stock Option Plan for Key Employees of Central Vermont Public Service Corporation.
			A 10.104	Form of Central Vermont Public Service Corporation Stock Option Agreement Pursuant to the 1997 Stock Option Plan for Key Employees of Central Vermont Public Service Corporation.
			31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
			31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
			32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
			32.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
	CENTRAL VERMONT PUBLIC SERVICE CORPORATION
	(Registrant)


By	/s/ Jean H. Gibson
	Jean H. Gibson Senior Vice President, Principal Financial Officer, and Treasurer

Dated November 8, 2004

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EXHIBIT INDEX
Exhibit Number	Exhibit Description
A 10.101	Form of Central Vermont Public Service Performance Share Agreement Pursuant to the Performance Share Incentive Plan.
A 10.102	Form of Central Vermont Public Service Corporation Stock Option Agreement Pursuant to the 2002 Long-Term Incentive Plan.
A 10.103	Form of Central Vermont Public Service Corporation Stock Option Agreement Pursuant to the 2000 Stock Option Plan for Key Employees of Central Vermont Public Service Corporation.
A 10.104	Form of Central Vermont Public Service Corporation Stock Option Agreement Pursuant to the 1997 Stock Option Plan for Key Employees of Central Vermont Public Service Corporation.
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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	September 30	December 31
	2004	2003
Assets
Net utility plant	$ -	$9,251
Other current assets	-	41
Total assets of discontinued operations	$ -	$9,292

Liabilities
Accounts payable	$ -	$1,749
Short-term debt (a)	-	3,750
Total liabilities of discontinued operations	$ -	$5,499

(a) Related to a Note Payable due to the Company that was paid on January 1, 2004.

Contractual Obligations	Payments Due by Period (in millions)
Contractual Obligations	Total	Less than 1 year (a)	1 to 3 years	3 to 5 years	More than 5 years
Long-term Debt - utility	$126.8	-	-	$3.0	$123.8
Interest on Long-term Debt - utility	116.4	$1.8	$14.6	14.6	85.4
Redeemable Preferred Stock	8.0	-	2.0	2.0	4.0
Purchased Power Contracts (b)	1,347.9	36.8	279.2	281.9	750.0
Capital Lease	11.0	0.3	2.2	1.8	6.7

Total Contractual Obligations	$1,610.1	$38.9	$298.0	$303.3	$969.9

(a) Includes payments due during the remainder of the current fiscal year. (b) Includes power contract commitments with Hydro-Quebec, VYNPC and various independent power producers. See Power Supply Matters below for more information related to these contracts.

2003 Earnings per diluted share		$.38

Year over Year Effects on Earnings:
Lower purchased power costs	.07
Higher resale sales	.06
Catamount - higher earnings	.05
Other	.03
Higher other operating revenue	.03
Lower retail and firm sales	(.02)
RS-2 power contract termination	(.13)
Subtotal		.09
		$.47
2004 Earnings per diluted share

	Three Months Ended September 30
	(dollars in thousands)
	2004		2003
	mWh	Amount	mWh	Amount
Energy	619,446	$25,762	646,256	$26,456
Capacity:
Capacity purchases		9,865		10,641
SFAS No. 5 loss accrual		-		-
Total purchased power		$35,627		$37,097

	2004 vs. 2003
	Third Quarter	Year to date
*Utility Business*
IRS tax settlement	-	$0.9
Interest income	$0.2	0.7
Cash surrender value of life insurance policies	-	(0.1)
Carrying costs on regulatory assets	-	(0.2)
Other	(0.2)	(0.6)
Unregulated Businesses
Catamount, excluding gain on sale of investments	1.5	2.1
Total Variance	$1.5	$2.8