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 June 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 No X

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. As of July 30, 2004 there were outstanding 12,128,769 shares of Common Stock, $6 Par Value.

Page 1 of 44

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 six months ended June 30, 2004 and 2003	3
	Condensed Consolidated Statements of Comprehensive Income (unaudited) for the three and six months ended June 30, 2004 and 2003	4
	Condensed Consolidated Balance Sheets as of June 30, 2004 (unaudited) and December 31, 2003	5
	Condensed Consolidated Statements of Retained Earnings (unaudited) for the three and six months ended June 30, 2004 and 2003	7
	Condensed Consolidated Statements of Cash Flows (unaudited) for the six months ended June 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	23
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	41
Item 4.	Controls and Procedures	41
PART II	OTHER INFORMATION	42
SIGNATURES		43
EXHIBIT INDEX		44

Page 2 of 44

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

	Three Months Ended June 30		Six Months Ended June 30
	2004 2003		2004 2003

Operating Revenues	$67,635	$73,588	$151,749	$153,064

Operating Expenses
Operation
Purchased power	34,365	37,495	92,287	77,033
Production and transmission	6,126	6,327	12,768	13,633
Other operation	10,718	10,194	21,880	22,687
Maintenance	4,219	3,519	7,843	6,738
Depreciation	4,044	3,971	8,072	7,944
Other taxes, principally property taxes	3,330	3,288	6,772	6,634
Taxes on income	845	2,617	(1,241)	5,377
Total operating expenses	63,647	67,411	148,381	140,046

Operating Income	3,988	6,177	3,368	13,018
Other Income and Deductions
Equity in earnings of affiliates	256	436	471	872
Allowance for equity funds during construction	19	15	48	31
Other income, net	2,149	1,804	3,808	2,464
Provision for income taxes	(651)	(564)	(1,185)	(997)
Total other income and deductions, net	1,773	1,691	3,142	2,370

Total Operating and Other Income	5,761	7,868	6,510	15,388
Interest Expense
Interest on long-term debt	2,534	2,832	5,022	5,675
Other interest (income) expense	(179)	243	-	327
Allowance for borrowed funds during construction	(8)	(7)	(20)	(14)
Total interest expense, net	2,347	3,068	5,002	5,988

Income from continuing operations	3,414	4,800	1,508	9,400
Income from discontinued operations, net of tax (including gain on disposal of $12,328 in 2004)	90	295	12,346	654
Net Income	3,504	5,095	13,854	10,054

Dividends on preferred stock	258	300	516	599

Earnings Available for Common Stock	3,246	4,795	13,338	9,455

Per Common Share Data:
Basic:
Earnings from continuing operations	$0.26	$0.38	$0.08	$0.74
Earnings from discontinued operations	$0.01	$0.02	$1.02	$0.06
Earnings per share	$0.27	$0.40	$1.10	$0.80

Diluted:
Earnings from continuing operations	$0.26	$0.38	$0.08	$0.73
Earnings from discontinued operations	$0.01	$0.02	$1.01	$0.06
Earnings per share	$0.27	$0.40	$1.09	$0.79

Average shares of common stock outstanding - basic	12,112,649	11,864,013	12,088,264	11,820,577
Average shares of common stock outstanding - diluted	12,264,781	12,057,931	12,272,099	12,006,282

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

Page 3 of 44

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

	Three Months Ended June 30		Six Months Ended June 30

	2004	2003	2004	2003
Net Income	$3,504	$5,095	$13,854	$10,054

Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments	(217)	434	(278)	251
Unrealized loss on securities	(473)	-	(470)	(62)
Comprehensive income	$2,814	$5,529	$13,106	$10,243

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

Page 4 of 44

CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)


	June 30 2004	December 31 2003
Assets	(unaudited)

Utility Plant, at original cost	$498,625	$495,162
Less accumulated depreciation	210,881	207,474
Net utility plant	287,744	287,688

Construction work-in-progress	10,164	9,988
Nuclear fuel, net	1,250	1,016
Total utility plant	299,158	298,692

Investments and Other Assets
Investments in affiliates	9,144	9,303
Non-utility investments	31,421	34,765
Non-utility property, less accumulated depreciation	2,141	2,236
Millstone decommissioning trust fund	4,377	4,340
Available for sale securities	22,245	-
Other	5,678	5,249
Total investments and other assets	75,006	55,893

Current Assets
Cash and cash equivalents	49,656	58,147
Restricted cash	592	2,000
Available for sale securities	13,237	-
Notes receivable	768	3,750
Accounts receivable, less allowance for uncollectible accounts ($1,349 in 2004 and $1,578 in 2003)	17,881	21,900
Unbilled revenues	13,313	17,505
Materials and supplies, at average cost	3,345	3,699
Prepayments	1,770	3,226
Other current assets	2,896	2,522
Assets held for sale	-	9,292
Total Current Assets	103,458	122,041

Deferred Charges and Other Assets
Regulatory assets	15,259	17,555
Other deferred charges - regulatory	32,834	30,929
Other	5,308	6,209
Total deferred charges and other assets	53,401	54,693

Total Assets	$531,023	$531,319

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

Page 5 of 44

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


	June 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)	$72,582	$72,119
Other paid-in capital	50,039	51,334
Accumulated other comprehensive income	(263)	485
Deferred compensation plans - employee stock ownership plans	172	(969)
Retained earnings	94,062	88,282
Total common stock equity	216,592	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	10,144	10,693
Total capitalization	368,540	365,748

Current Liabilities
Current portion of preferred stock	1,000	1,000
Current portion of long-term debt	-	2,657
Accounts payable	4,236	6,650
Accounts payable - affiliates	8,268	10,985
Accrued income taxes	3,867	196
Accrued interest	2,688	2,801
Dividends declared	2,785	-
Nuclear decommissioning costs	4,807	4,026
Other current liabilities	15,803	18,697
Liabilities of assets held for sale	-	5,499
Total current liabilities	43,454	52,511

Deferred Credits and Other Liabilities
Deferred income taxes	31,029	36,713
Deferred investment tax credits	4,668	4,880
Nuclear decommissioning costs	19,836	22,934
Asset retirement obligations	3,546	3,449
Other	59,950	45,084
Total deferred credits and other liabilities	119,029	113,060

Commitments and Contingencies

Total Capitalization and Liabilities	$531,023	$531,319

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

Page 6 of 44

CONDENSED CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(Dollars in thousands)
(unaudited)

	Three Months Ended June 30		Six Months Ended June 30
	2004 2003		2004 2003
Retained Earnings at Beginning of Period	$93,604	$79,640	$88,282	$80,077
Net Income from continuing operations	3,414	4,800	1,508	9,400
Net Income from discontinued operations	90	295	12,346	654
Retained Earnings Before Dividends	97,108	84,735	102,136	90,131

Cash Dividend Declared
Preferred Stock	258	300	516	599
Common Stock	2,788	2,625	8,338	7,806
Total Dividends Declared	3,046	2,925	8,854	8,405
Performance Share Plan	-	-	780	-
Other Adjustments	-	(55)	-	29
Retained Earnings at End of Period	$94,062	$81,755	$94,062	$81,755

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

Page 7 of 44

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

	Six Months Ended June 30
	2004	2003
Cash Flows Provided (Used) By:
Operating Activities
Net income from continuing operations	$1,508	$9,400
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of affiliates	(471)	(872)
Dividends received from affiliates	538	775
Equity in earnings from non-utility investments	(2,603)	(4,146)
Distribution of earnings from non-utility investments	6,384	4,947
Depreciation	8,072	7,944
Amortization of capital leases	549	548
Deferred income taxes and investment tax credits	(3,588)	(1,453)
Net amortization of nuclear replacement energy and maintenance costs	(1,524)	327
Amortization of conservation and load management costs	-	1,108
Reserve for loss on power contract (SFAS No. 5 loss accrual)	14,351	-
Amortization of SFAS 5 loss accrual	(598)	-
Vermont Yankee replacement energy deferral	(558)	-
Decrease in accounts receivable and unbilled revenues	5,643	3,360
Decrease in accounts payable	(4,698)	(2,486)
Decrease (increase) in accrued income taxes	(5,928)	215
Decrease (increase) in current assets	662	(861)
Decrease in current liabilities	(2,556)	(509)
Increase in pension and benefit obligations	2,372	1,772
Decrease in long-term assets	3,262	1,976
Decrease in long-term liabilities and other	(5,823)	(1,054)
Restricted cash - regulatory liability	(592)	-
Net cash provided by operating activities of continuing operations	14,402	20,991
Investing Activities
Construction and plant expenditures	(9,321)	(6,358)
Conservation and load management expenditures	(65)	(80)
Return of capital	173	47
Investments in available for sale securities	(35,596)	-
Other investments, net	(65)	(118)
Net cash used for investing activities of continuing operations	(44,874)	(6,509)
Financing Activities
Proceeds from exercise of stock options	391	1,246
Proceeds from dividend reinvestment program	966	912
Retirement of preferred stock	(2,000)	-
Retirement of long-term debt	(2,660)	(15,359)
Restricted cash	2,000	-
Common and preferred dividends paid	(6,069)	(5,491)
Reduction in capital lease obligations	(549)	(548)
Net cash used for financing activities of continuing operations	(7,921)	(19,240)

Effect of exchange rate changes on cash	(41)	(88)

Cash flows provided by (used for) discontinued operations	29,943	(144)

Net Decrease in Cash and Cash Equivalents	(8,491)	(4,990)
Cash and Cash Equivalents at Beginning of Year	58,147	60,364
Cash and Cash Equivalents at End of Year	$49,656	$55,374
Supplemental Cash Flow Information
Cash paid during the year for:
Interest (net of amounts capitalized)	$4,731	$6,180
Income taxes (net of refunds)	$10,271	$7,923

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

Page 8 of 44

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

About Central Vermont Public Service Corporation Central Vermont Public Service Corporation (the "Company") is a Vermont-based electric utility that transmits, distributes and sells electricity, 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 second quarter and first half 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 Exchang e 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 its 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):

	June 30	December 31
Net Regulatory Assets, Deferred Charges and Regulatory Liabilities	2004	2003
Regulatory assets *
Conservation and load management ("C&LM")	$612	$517
Nuclear refueling outage costs - Millstone	1,075	109
Income taxes	4,414	5,640
Maine Yankee nuclear power plant dismantling costs (a)	6,465	7,287
Connecticut Yankee nuclear power plant dismantling costs (a)	2,545	2,980
Unrecovered plant and regulatory study costs (b)	-	874
Other regulatory assets	148	148
Subtotal Regulatory assets	15,259	17,555

Other deferred charges - regulatory
Vermont Yankee fuel rod maintenance deferral **	3,247	3,101
Vermont Yankee sale costs **	8,979	8,704
Vermont Yankee replacement energy deferral (c)	558	-
Yankee Atomic incremental dismantling costs (a)	7,187	7,481
Connecticut Yankee incremental dismantling costs (a)	10,477	10,347
Unrealized loss on power contract derivatives	2,386	1,296
Subtotal Other deferred charges - regulatory	32,834	30,929





Page 9 of 44
Other deferred credits ***
Millstone Decommissioning	463	304
IPP Settlement Reimbursement and VEPPI cost mitigation	985	757
Vermont utility mandated earnings cap	3,368	3,220
Vermont Yankee NEIL Insurance refund (d)	592	461
Asset Retirement Obligation - Millstone Unit #3	831	891
Unrealized gain on power contract derivative	-	444
Other regulatory liabilities	541	602
Subtotal Other deferred credits	6,780	6,679

Net Regulatory assets, deferred charges and other deferred credits	$41,313	$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 next 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 next 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 is offset against the 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 6, 2004. In the second quarter of 2004, based on the preliminary Accounting Order, the Company deferred about $0.6 million of incremental replacement power costs incurred for the period June 18-30, 2004. 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, 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; the two provisions are stayed until the PSB issues its Final Accounting Order.
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):

	June 30 2004	December 31 2003
Accrued pension benefits	$14,163	$12,562
Accrued postretirement medical and other benefits	8,649	7,877
Environmental reserve (long-term portion)	5,161	5,983
Non-legal asset retirement obligation	5,678	5,226
Other deferred credits - regulatory	6,780	6,679
Deferred tax liabilities	4,303	4,451
Reserve for loss on power contract	12,557	-
Other	2,659	2,306
Total	$59,950	$45,084

Page 10 of 44

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

	June 30 2004	December 31 2003
Accrued employee costs - payroll and medical	$3,670	$3,373
Other taxes and Energy Efficiency Utility	1,801	3,254
Deferred compensation plans	2,759	2,749
Customer deposits, prepayments and interest	1,246	2,021
Obligation under capital leases	1,097	1,097
Environmental and accident reserves	1,921	1,755
Accrued joint-owned expenses	143	302
Reserve for loss on power contract	1,196	-
Miscellaneous accruals	1,970	4,146
Total	$15,803	$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"). 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 - Discontinued 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 loss accrual. Additionally, the loss accrual will be reversed and amortized on a straight-line basis through 2015, as required by GAAP.

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 second quarter and first half 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 June 30		Six Months Ended June 30
	2004	2003	2004	2003
Earnings available for common stock, as reported	$3,246	$4,795	$13,338	$9,455
Deduct: Total stock-based employee compensation*	213	135	213	135

Pro forma net income	$3,033	$4,660	$13,125	$9,320

Earnings per share:
Basic - as reported	$0.27	$0.40	$1.10	$0.80
Basic - pro forma	$0.25	$0.39	$1.08	$0.79

Diluted - as reported	$0.27	$0.40	$1.09	$0.79
Diluted - pro forma	$0.25	$0.39	$1.07	$0.78

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

Page 11 of 44

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 June 30, 2004 is related to 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.

Variable Interest Entities: In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities ("FIN 46") and in December 2003 the FASB issued its revision ("FIN 46R") which addressed the requirements for consolidating certain variable interest entities ("VIEs"). This interpretation clarified application of Accounting Research Bulletin No. 51, "Consolidated Financial Statements," and replaced current accounting guidance relating to consolidation of certain special purpose entities. FIN 46 and FIN 46R define VIEs as entities that are unable to finance their ongoing operations without additional subordinated financing. FIN 46R requires identification of the Company's participation in VIEs and consolidation of those VIEs of which the Company is the primary beneficiary. The company adopted FIN 46 at December 31, 2003 and FIN 46R at March 31, 2004, and was not required to consolidate any existing interests pursuant to the req uirements of FIN 46 or FIN 46R. See Note 2 - Investments in Affiliates.

NOTE 2 - INVESTMENTS IN AFFILIATES

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

	Three Months Ended June 30		Six Months Ended June 30
Earnings	2004	2003	2004	2003
Operating revenues	$25,052	$49,014	$74,197	$96,982
Operating income (loss)	$6	$326	$(168)	$554
Net income	$128	$722	$271	$1,407

Company's equity in net income	$75	$240	$160	$467

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 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 $8.8 million for the second quarter and $26 million for the first half of 2004, and $17.1 million and $33.8 million for the same periods in 2003.

Page 12 of 44

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

	Three Months Ended June 30		Six Months Ended June 30
Earnings	2004	2003	2004	2003
Transmission revenues	$6,543	$5,635	$12,876	$11,270
Operating income	$1,773	$1,378	$3,201	$2,750
Net income	$307	$349	$618	$622

Company's equity in net income	$154	$158	$275	$329

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. The decrease reflects acquisitions of non-voting common stock issued by VELCO in amounts below the Company's pro-rata ownership at the time of purchase. 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 VELCO's primary beneficiary. Therefore, VELCO's 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 $2.6 million for the second quarter and $5.2 million for the first half of 2004, and $2.5 million and $5.7 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 June 30, 2004, Catamount had interests in nine operating independent power projects located in Rumford, Maine; East Ryegate, Vermont; Hopewell, Virginia; Rupert and Glenns Ferry, Idaho; 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 Wales 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.

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 which will be recorded in the third quarter of 2004.

Fibrothetford Limited ("Fibrothetford") Catamount continues to discuss the sale of its Fibrothetford investment interests with third parties following the termination of a Sales and Purchase Agreement with a third party in December 2003. Catamount cannot predict whether a sale will ultimately be consummated.

Eversant As of June 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.

Page 13 of 44

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. 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 the Company's power contracts that were in place to supply power to Connecticut Valley.

For the first half 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 second 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
June 30

Six Months Ended
June 30

    2004

     2003

    2004

     2003

Operating revenues

$24

$4,701

$24

$9,803

Operating expenses

   Purchased power

-

3,518

-

7,396

   Other operating (income) expenses

(200)

493

43

1,019

   Income tax expense (benefit)

     70

     280

       (15)

     579

   Total operating (income) expenses

(130)

  4,291

         28

  8,994

Operating income (loss) income

154

410

(4)

809

Other (expense) income, net

     (6)

   (115)

         22

   (155)

Net income, net of tax

148

295

18

654

Gain from disposal, net of $8,688 tax for the six months ended

   (58)

         -

  12,328

         -

Income from discontinued operations, net of tax

   $90

   $295

$12,346

   $654

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):

June 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.

Page 14 of 44

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 June 30, 2004, these investments included $13.2 million with maturities up to one year, and $22.3 million with maturities greater than one year. Investments with maturities up to one year 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. The fair value includes about $360,000 of accrued interest and other. Information regarding available for sale securities as of June 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	$5,068	-	$5,068	-	$(22)
US Government Agencies	22,127	4,074	$17,965	22,039	$4	(271)
Corporate Bonds	8,443	4,095	4,280	8,375	-	(181)
Total	$35,596	$13,237	$22,245	$35,482	$4	$(474)

NOTE 6 - LONG-TERM DEBT

Utility At June 30, 2004, total utility long-term debt maturities and sinking fund requirements consisted of the $75 million related to the $75 million Second Mortgage Bonds that matured on August 1, 2004. This debt remains classified as long term on the Condensed Consolidated Balance Sheet. No payments are due on long-term debt for 2005 through 2007. At June 30, 2004, substantially all utility property and plant were subject to liens under the first and second mortgage bonds and the Company was in compliance with all debt covenants.

The Company received the regulatory approvals and waivers needed to issue First Mortgage Bonds, and on May 28, 2004, the Company priced First Mortgage Bonds intended to refinance and replace the Second 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 of this sale were used to repay in full our $75 million of 8.125 percent Second Mortgage Bonds on August 2, 2004.

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

Page 15 of 44

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 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 April 30, 2004, the PSB issued an Order adopting a proposed schedule that anticipates proceedings through 2004 with a final order in March 2005, and includes a provision for the Company to file for a rate increase effective April 1, 2005. The Company cannot predict the outcome of the rate investigation at this time.

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 percent rate increase, expected to be effective April 1, 2005, and requested that the two cases be consolidated. The Company cannot predict the outcome of its request at this time.

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 June 30		Six Months Ended June 30
	2004	2003	2004	2003
Income from continuing operations	$3,414	$4,800	$1,508	$9,400
Income from discontinued operations, net of tax	90	295	12,346	654
Net Income	3,504	5,095	13,854	10,054
Preferred stock dividend requirements	258	300	516	599
Earnings available for common stock	$3,246	$4,795	$13,338	$9,455

Average shares of common stock outstanding - basic	12,112,649	11,864,013	12,088,264	11,820,577
Dilutive effect of stock options	124,009	101,087	155,712	92,874
Dilutive effective of performance plan shares	28,123	92,831	28,123	92,831
Average shares of common stock outstanding - diluted	12,264,781	12,057,931	12,272,099	12,006,282

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 reviewed annually, 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.

Page 16 of 44

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.

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

	Pension Benefits		Postretirement Benefits
	Three Months Ended June 30		Three Months Ended June 30
	2004	2003	2004	2003
Service cost	$755	$686	$135	$105
Interest cost	1,388	1,371	389	327
Expected return on plan assets	(1,406)	(1,489)	(108)	(77)
Amortization of prior service cost	99	99	-	-
Recognized net actuarial loss	-	-	345	211
Amortization of transition (asset) obligation	(37)	(37)	64	64
Net periodic benefit cost	799	630	825	630
Less amount allocated to other accounts	127	106	131	106
Net benefit costs expensed	$672	$524	$694	$524

	Pension Benefits		Postretirement Benefits
	Six Months Ended June 30		Six Months Ended June 30
	2004	2003	2004	2003
Service cost	$1,510	$1,372	$270	$210
Interest cost	2,776	2,742	778	654
Expected return on plan assets	(2,812)	(2,978)	(216)	(154)
Amortization of prior service cost	198	198	-	-
Recognized net actuarial loss	-	-	690	422
Amortization of transition (asset) obligation	(74)	(74)	128	128
Net periodic benefit cost	1,598	1,260	1,650	1,260
Less amount allocated to other accounts	251	212	259	212
Net benefit costs expensed	$1,347	$1,048	$1,391	$1,048

Plan Assets Pension costs and cash funding requirements are expected to increase in future years. At June 30, 2004, the market value of pension plan trust assets was $61.7 million, including $41.4 million in marketable equity securities, $19.6 million in debt securities and $0.7 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 The Company made no contributions to the pension plan in the first six months of 2004; however, expects to pay the minimum contribution of $1.1 million for the 2003 plan year in the third quarter of 2004. There was no pension contribution payment made in 2003. The Company paid $0.9 million for net postretirement benefit payments in the first half of 2004 and in the first half of 2003 and expects annual 2004 contributions of $3.3 million compared to annual 2003 contributions of $2.5 million.

Page 17 of 44

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. The Company has concluded that the effect is not significant. Therefore, 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, dividends, 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. This rate change reduced regulatory tax assets by about $1 million, and decreased state income tax expense by about $0.1 million in the second quarter of 2004.

In the first quarter of 2004, taxes on income included a $5.9 million benefit related to a 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.

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, 2004 and is expected to take approximately seven weeks. None of the Yankee plants have included any allowance for potential recovery of these claims in their FERC-filed cos t 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 June 30, 2004, the Company had regulatory assets of about $6.5 million related to Maine Yankee and $2.5 million related to Connecticut Yankee. These estimated costs are being collected from the Company's customers through existing retail rate tariffs. At June 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. 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.

Page 18 of 44

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 $13 million. The timing, amount and outcome of the matters 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.

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, including challenging the legal availability of the remedies requested by Bechtel. 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 scheduled an August 26, 2004 hearing on the legal availability of the remedies requested by Bechtel. A hearing on the other PJR issues, if necessary, has been scheduled to b egin on October 19, 2004.

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 $823 million covers the time period 2000 - 2023 and represents an aggregate increase of approximately $389 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. FERC has not acted on 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. Connecticut Yankee anticipates that the process of resolving the matters in the 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 19 of 44

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.

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.

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.

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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 June 30, 2004, a $6.6 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.

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 Company'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):

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

2004
Revenues from external customers	$67,635	$232	$469	-	$(701)	$67,635
Intersegment revenues	24	-	-	-	(24)	-
Equity income - utility affiliates (2)	256	-	-	-	-	256
Equity income - non-utility affiliates (3)	-	1,130	-	-	(1,130)	-
Income from continuing operations	3,268	37	109	-	-	3,414
Income from discontinued operations, net of tax (4)	-	-	-	$90	-	90
Assets held for sale at June 30, 2004 (4)	-	-	-	-	-	-
Total assets at June 30, 2004	483,826	44,458	3,802	-	(1,063)	531,023
2003
Revenues from external customers	$73,588	$139	$485	-	$(624)	$73,588
Intersegment revenues	23	-	-	-	(23)	-
Equity income - utility affiliates (2)	436	-	-	-	-	436
Equity income - non-utility affiliates (3)	-	2,020	-	-	(2,020)	-
Income (loss) from continuing operations	4,430	233	137	-	-	4,800
Income from discontinued operations, net of tax (4)	-	-	-	$295	-	295
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

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

2004
Revenues from external customers	$151,749	$1,249	$945	-	$(2,194)	$151,749
Intersegment revenues	46	-	-	-	(46)	-
Equity income - utility affiliates (2)	471	-	-	-	-	471
Equity income - non-utility affiliates (3)	-	2,603	-	-	(2,603)	-
Income from continuing operations	665	618	225	-	-	1,508
Income from discontinued operations, net of tax (4)	-	-	-	12,346	-	12,346
Assets held for sale at June 30, 2004 (4)	-	-	-	-	-	-
Total assets at June 30, 2004	483,826	44,458	3,802	-	(1,063)	531,023
2003
Revenues from external customers	$153,064	$191	$986	-	$(1,177)	$153,064
Intersegment revenues	51	-	-	-	(51)	-
Equity income - utility affiliates (2)	872	-	-	-	-	872
Equity income - non-utility affiliates (3)	-	4,146	-	-	(4,146)	-
Income from continuing operations	9,057	96	247	-	-	9,400
Income from discontinued operations, net of tax (4)	-	-	-	$654	-	654
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,
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. While Catamount has sufficient cash flow to cover its operating expenses, additional project investments will require financing or additional funding from us. Catamount partnered with Marubeni Power International, Inc. in 2004 for the purpose of developing wind energy projects in the Northeast region of the U.S. and is seeking investors and partners to co-invest in the development, ownership and acquisition of other projects. 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. 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 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.

Page 23 of 44

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 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 April 30, 2004, the PSB issued an Order adopting a proposed schedule that anticipates proceedings through 2004 with a final order in March 2005, and includes a provision for us to file for a rate increase effective April 1, 2005. We cannot predict the outcome of the rate investigation at this time.

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 percent rate increase, expected to be effective April 1, 2005, and we requested that the two cases be consolidated. At this time, we cannot predict the outcome of our requests.

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 The authorization 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 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." The program will be 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 betw een acquiring the renewable energy and our alternative cost of power. The program will require 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 The authorization of 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 affected 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.

Page 24 of 44

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 our regulated Vermont service territory and FERC-regulated wholesale businesses. If we determine the Company no longer meets the criteria under SFAS No. 71, the accounting impact would be an extraordinary charge to operations of about $41.3 million on a pre-tax basis as of June 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 our overall net power costs. The volatility of wholesale power market prices can impact these mitigation efforts.

Interest Rate Risk We have $16.3 million of Industrial Development/Pollution Control bonds outstanding as of June 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 June 30, 2004, our pension trust held marketable equity securities in the amount of $41.4 million and our Millstone Unit #3 decommissioning trust held marketable equity securities of $3.3 million. We also maintain a variety of insurance policies in a Rabbi Trust with a current value of $5.4 million to support various supplemental retirement and deferred compensation plans. The current values of certain policies are affected by changes in the equity market.

Unregulated Business  Catamount is wholly focused on developing, owning and operating wind energy projects and is continuing to pursue sales of its interests in non-wind electric generating assets.  Catamount's future success is dependent on the acceptance of wind power as an energy source by large producers, utilities, and other purchasers of electricity. In addition, there is no guarantee of 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 a partner or obtaining additional funding from the Company.

Catamount is anticipating entering into a construction lending arrangement for an amount up to about $27.2 million for a wind project located in the United States. The construction loan will be funded by Catamount's operating cash and a short-term loan from the Company to Catamount. The construction loan will be subject to typical conditions precedent and upon the wind project achieving substantial completion and satisfaction of other equity funding conditions, the construction loan would be paid off. However, there is no assurance that substantial completion of the project will be achieved. After the construction loan is paid off, Catamount will maintain an equity investment in the wind project.

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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"), 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. 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 the Company's 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
June 30

Six Months Ended
June 30

    2004

     2003

    2004

     2003

Operating revenues

$24

$4,701

$24

$9,803

Operating expenses

   Purchased power

-

3,518

-

7,396

   Other operating (income) expenses

(200)

493

43

1,019

   Income tax expense (benefit)

     70

     280

       (15)

     579

   Total operating (income) expenses

(130)

  4,291

         28

  8,994

Operating income (loss)

154

410

(4)

809

Other (expense) income, net

    (6)

   (115)

          22

   (155)

Net income, net of tax

148

295

18

654

Gain from disposal, net of $8,688 tax for the six months ended

   (58)

         -

  12,328

         -

Income from discontinued operations, net of tax

$90

   $295

$12,346

   $654

Page 26 of 44

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):

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 New Hampshire Public Utilities Commision ("NHPUC") Order in which it told Connecticut Valley to stop buying power from the Company.

LIQUIDITY AND CAPITAL RESOURCES

At June 30, 2004, we had cash and cash equivalents of $49.6 million and working capital of $60 million. In the first half of 2004, cash and cash equivalents decreased $8.5 million, reflecting net cash provided by operating activities of $14.4 million. Net cash used by investing activities amounted to $44.9 million mostly for investments in available for sale securities and construction expenditures. Net cash used in financing activities was $7.9 million, related to dividends paid on common and preferred stock and retirement of long-term debt. Cash provided by discontinued operations amounted to about $29.9 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 June 30, 2004, these investments included $13.2 million with maturities up to one year, and $22.3 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 shareholder equity from about 10 percent of its total assets to about 25 percent. Construction is scheduled to begin in early 2005 and will extend through 2007. On July 21, 2004, we filed jointly with Green Mountain Power Corporation ("GMP") for authorization from FERC to purchase stock to be issued by VELCO, pending approval by the PSB, in connection with financing its planned transmission upgrades. 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
Our significant contractual obligations as of June 30, 2004 are summarized in the table below.

Contractual Obligations

Payments Due by Period (in millions)

Total

Remainder of
        2004

2005 & 2006

2007 & 2008

Thereafter

Long-term Debt - utility (a)

$126.8

$75.0

-

$3.0

$48.8

Redeemable Preferred Stock

8.0

-

$2.0

2.0

4.0

Purchased Power Contracts (b)

1,379.3

68.2

279.2

281.9

750.0

Capital Lease

       11.3

    0.6

     2.2

     1.8

     6.7

   Total Contractual Obligations

$1,525.4

$143.8

$283.4

$288.7

$809.5

(a) See Financing discussion below.

(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.

Financing
Utility At June 30, 2004, total utility long-term debt maturities and sinking fund requirements consisted of the $75 million of Second Mortgage Bonds that matured on August 1, 2004. This debt remains classified as long term. No payments are due on long-term debt for 2005 through 2007. At June 30, 2004, substantially all utility property and plant were subject to liens under the First and Second Mortgage Bonds and the Company was in compliance with all debt covenants.

In May 2004, the PSB approved our request to issue $75 million of first mortgage bonds in the private placement market. On May 28, 2004, we priced First Mortgage Bonds intended to refinance and replace the Second 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 refinancing and lower interest rates will reduce annual interest expense by about $2 million on a pre-tax basis. The proceeds of this sale were used to repay in full our $75 million of 8.125 percent Second Mortgage Bonds on August 2, 2004.

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 is now soliciting 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 solicit and enter into an appropriately priced corporate and/or development credit facility.

Catamount is anticipating entering into a construction lending arrangement for an amount up to about $27.2 million for a wind project located in the United States. The construction loan will be funded by Catamount's operating cash and a short-term loan from the Company to Catamount. The construction loan will be subject to typical conditions precedent and upon the wind project achieving substantial completion and satisfaction of other equity funding conditions, the construction loan would be paid off. However, there is no assurance that substantial completion of the project will be achieved. 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 GAAP, requiring us to make estimates and judgments that affect reported amounts of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of the Condensed Consolidated Financial Statements. See Critical Accounting Policies and Estimates in Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report filed on Form 10-K for a discussion of the estimates and judgments necessary in our accounting for regulation, 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:

Page 28 of 44

Regulation If we determine the Company no longer meets the criteria under SFAS No. 71, the accounting impact would be an extraordinary charge to operations of about $41.3 million on a pre-tax basis as of June 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 reviewed annually, 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 second quarter and $1.6 million for the first half of 2004. Of these amounts, $0.7 million is reflected in results of operations for the second quarter and $1.4 million for the first half, with the remaining amounts capitalized for accounting purposes. This compares to pension costs of $0.6 million for the second quarter and $1.3 million for the first half of 2003. Of these amounts, $0.5 million is reflected in results of operations for the second quarter and $1 million for the first half, with the remaining amounts capitalized for accounting purposes.

Pension costs and cash funding requirements are expected to increase in future years. At June 30, 2004, the market value of pension plan trust assets was $61.7 million, including $41.4 million in marketable equity securities, $19.6 million in debt securities and $0.7 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 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 extend through 2015.

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     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 loss accrual. Additionally, the loss accrual will be reversed and amortized on a straight-line basis through 2015, as required by GAAP.

RESULTS OF OPERATIONS
     The following sections of Management's Discussion and Analysis compare the results of operations for the second quarter and first half 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 second quarter earnings were $3.5 million, or 27 cents per basic and diluted share of common stock. This compares to second quarter 2003 earnings of $5.1 million, or 40 cents per basic and diluted share of common stock.

For the first half of 2004, earnings were $13.9 million, or $1.10 per basic and $1.09 per diluted share of common stock, a $3.8 million increase from a year ago. Earnings for the first half of 2003 totaled $10.1 million, or 80 cents per basic and 79 cents per diluted share of common stock.

On January 1, 2004, Connecticut Valley completed the sale of substantially all of its plant assets and franchise. In the second quarter of 2003, when the sale became probable, its operations were required to be presented in the financial statements as discontinued operations. Net income from discontinued operations for the first six months of 2004 amounted to $12.3 million, reflecting a gain, net of tax, of $12.3 million, or $1.02 per basic and $1.01 per diluted share of common stock. Second quarter 2004 net income from discontinued operations amounted to 1 cent per basic and diluted share of common stock. This compares to 2003 net income from discontinued operations of 2 cents per basic and diluted share of common stock for the second quarter and 6 cents for the first six months.

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, 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 favorable net impact of $3.9 million, or 32 cents per basic and diluted share of common stock.

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

Second quarter 2004 vs. second quarter 2003:

2003 Earnings per diluted share

$.40

Year over Year Effects on Earnings:

Lower purchased power costs

.15

IRS tax settlement received in the second quarter of 2004

.09

Higher retail and firm sales

.03

Higher other operating revenue

.01

Higher other costs

(.06)

Catamount - lower earnings

(.02)

RS-2 power contract termination - no sales in 2004

(.12)

Lower resale sales

(.21)

Subtotal

(.13)

2004 Earnings per diluted share

$.27

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First six months 2004 vs. first six months 2003:

2003 Earnings per diluted share

$.79

Year over Year Effects on Earnings:

Higher retail and firm sales

.14

IRS tax settlement received in the second quarter of 2004

.09

Higher other operating revenue

.04

Catamount higher earnings

.04

Higher resale sales

.02

Lower other costs

.01

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

(.04)

Discontinued operations - 2003

(.06)

RS-2 power contract termination - no sales in 2004

(.26)

             Subtotal

(.02)

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

$1.09

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 our 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 six months ended June 2004 and 2003 are summarized below:

	Three Months Ended June 30
	mWh		Revenues (000's)
	2004	2003	2004	2003
Retail sales:
Residential	208,821	208,599	$28,128	$28,037
Commercial	200,540	196,087	24,530	24,167
Industrial	95,932	92,614	7,865	7,875
Other retail	1,355	1,346	399	400
Total retail sales	506,648	498,646	60,922	60,479
Resale sales:
Firm (1)	973	1,152	110	29
RS-2 power contract (2)	-	28,081	-	2,453
Other resale sales	98,552	200,929	4,459	8,719
Total resale sales	99,525	230,162	4,569	11,201
Other revenues	-	-	2,144	1,908
Total	606,173	728,808	$67,635	$73,588

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	Six Months Ended June 30
	mWh		Revenues (000's)
	2004	2003	2004	2003
Retail sales:
Residential	491,257	481,618	$64,313	$62,951
Commercial	415,993	410,034	50,155	49,368
Industrial	207,398	194,393	17,385	16,807
Other retail	2,709	2,695	801	797
Total retail sales	1,117,357	1,088,740	132,654	129,923
Resale sales:
Firm (1)	2,377	2,649	163	89
RS-2 power contract (2)	-	60,485	-	5,315
Other resale sales	277,748	306,301	14,646	14,247
Total resale sales	280,125	369,435	14,809	19,651
Other revenues	-	-	4,286	3,490
Total	1,397,482	1,458,175	$151,749	$153,064

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 $6 million for the second quarter of 2004 compared to 2003 due to the following factors:

The January 1, 2004 termination of the power contract with Connecticut Valley decreased revenue by $2.4 million.
Other resale sales decreased $4.3 million due to fewer mWh available for resale resulting from 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 beginning June 18. This was partially offset by an additional 28,000 mWh available for resale due to the termination of the power contract with Connecticut Valley.
Retail and firm sales increased $0.5 million due to a 1.6 percent increase in volume mostly related to higher usage by commercial and industrial customers.
Other operating revenue increased $0.2 million primarily due to higher pole attachment revenue and contract service billing.

Operating revenues decreased $1.3 million for the first half of 2004 compared to 2003 due to the following factors:

The January 1, 2004 termination of the power contract with Connecticut Valley decreased revenue by $5.3 million.
Other Resale sales increased $0.4 million primarily due to higher contract prices for forward sales in the first quarter of 2004, partially offset by fewer mWh available for resale. The mWh volume decreased about 9 percent due to the nuclear plant outages described above, partially offset by an additional 60,500 mWh available from the termination of the power contract with Connecticut Valley.
Retail and firm sales increased $2.8 million due to a 2.6 percent increase in volume mostly related to colder weather in the first quarter of 2004.
Other operating revenue increased $0.8 million due to higher pole attachment revenue, transmission revenue and contract service billing.

Purchased Power: The cost components of purchased power for the three and six months ended June 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 June 30

(dollars in thousands)

2004

2003

mWh

Amount

mWh

Amount

  Energy

550,926

$24,179

648,289

$27,370

  Capacity:

     Capacity purchases

10,186

10,125

     SFAS No. 5 loss accrual

            -

          -

Total purchased power

$34,365

$37,495

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Six Months Ended June 30

(dollars in thousands)

2004

2003

mWh

Amount

mWh

Amount

  Energy

1,273,214

$57,543

1,326,701

$56,375

  Capacity:

     Capacity purchases

20,393

20,658

     SFAS No. 5 loss accrual

  14,351

           -

Total purchased power

$92,287

$77,033

Purchased power expense decreased $3.1 million, pre-tax, in the second quarter of 2004 compared to 2003 as a result of the following factors:

Purchases primarily under long-term power contracts decreased $8.9 million, mostly related to a scheduled outage at the Vermont Yankee plant in May 2004 and a 19-day unscheduled outage at the Vermont Yankee plant beginning June 18, 2004 due to a transformer fire at the plant, and lower deliveries under the Hydro-Quebec contract.
Short-term power purchases, including those purchased through ISO-New England, increased $5.7 million, primarily related to purchases of replacement power due to the Vermont Yankee plant outages and a scheduled outage at Millstone Unit #3. By comparison, there were no outages at these plants in the second quarter of 2003. On July 12, 2004, the PSB approved a preliminary Accounting Order for deferral of incremental replacement energy costs incurred as a result of the Vermont Yankee plant's June 2004 unscheduled outage. Therefore, incremental replacement energy costs of about $0.6 million incurred from June 18 to 30, did not affect second quarter 2004 results.
Other purchased power costs increased $0.1 million due to a second quarter 2003 reimbursement of payment for an outstanding dispute related to Merrimack, partially offset by monthly reversals of the loss accrual related to the Connecticut Valley power contract described below.

Purchased power expense increased $15.3 million, pre-tax, for the first half 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 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 the Company's power contracts that were in place to source the Connecticut Valley power contract. Such reversals amounted to $0.6 million in the first half of 2004 and are recorded in capacity costs.
Purchases under long-term power contracts with Vermont Yankee, Hydro-Quebec and Independent Power Producers decreased $6.6 million primarily due to the second quarter 2004 Vermont Yankee plant outages.
Short-term purchases, including those purchased through ISO-New England, increased $8.3 million due to purchases of replacement energy as a result of the second quarter 2004 nuclear plant outages described above, and higher market prices for those purchases versus market prices for the same period in 2003.
Other purchased power costs decreased $0.2 million primarily due to lower ISO-NE capacity costs.

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 second quarter and first half 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 $0.9 million decrease for the first half of 2004 is primarily due to lower production 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 $0.5 million for the second quarter and decreased $0.8 million for the first half of 2004. Both periods reflect the favorable impact of an insurance settlement received in the second quarter of 2004, and conservation and load management amortizations in 2003 versus none in 2004. Other factors affecting these expenses included higher employee-related costs (pension and medical), and higher bad debt expense related to a second quarter 2004 customer bankruptcy.

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Maintenance This is primarily related to costs associated with maintaining our electric distribution system such as tree trimming and maintenance of overhead lines. These costs increased $0.7 million for the second quarter and $1.1 million for the first half of 2004, mostly related to higher storm restoration costs due to storm activity in the second quarter of 2004, and higher pole attachment 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. This rate change reduced regulatory tax assets by about $1 million, and decreased state income tax expense by about $0.1 million in the second quarter of 2004.

In the first quarter of 2004, taxes on income included a $5.9 million benefit related to a 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 of $0.2 million for the second quarter and $0.4 million for the first half of 2004 is primarily related to lower VYNPC interest income due to delayed distribution of sale proceeds in 2003.

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 $0.3 million for the second quarter and $1.3 million for the first half of 2004 is explained in the table below (dollars in millions):

2004 vs. 2003

Second Quarter

Year to date

        Utility Business

          IRS tax settlement

0.9

0.9

          Interest income

0.4

0.5

          Cash surrender value of life insurance policies

(0.2)

(0.1)

          Other

(0.5)

(0.6)

        Unregulated Businesses

          Catamount revenues and expenses

  (0.3)

  0.6

Total Variance

   $0.3

$1.3

     Utility Business  The IRS tax settlement is described in Taxes on Income above. Interest income increased mostly related to available for sale securities. The cash surrender value of certain life insurance policies decreased due to financial market results, partially offset by death benefit proceeds of about $0.3 million received in the second quarter of 2004. Other items include various deductions, miscellaneous revenue, and adjustments that resulted in an unfavorable variance.

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

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 $0.2 million increase for the first half of 2004 is primarily due to higher Catamount earnings during that period.

Interest on long-term debt: Interest expense on long-term debt includes the utility business and our unregulated businesses. The decrease of $0.3 million for the second quarter and $0.7 million for the first half of 2004 is primarily related to lower utility and Catamount long-term debt.

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Other interest expense: Other interest expense includes the utility business and our unregulated businesses. The $0.4 million decrease for the second quarter and first half of 2004 is related to an IRS tax settlement, described above.

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 our 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 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, the Company 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 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 tra nsmission 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 the Company, 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,

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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 the Company and Hydro-Quebec, which extend through 2016. There are specific contractual provisions that provide that in the event any VJO member fails to meet its obligation under the contract with Hydro-Quebec, the remaining VJO participants, including the Company, must "step-up" to the defaulting party's share on a pro rata basis. Under the existing contracts with Hydro-Quebec, we purchased $13.1 million of energy and related capacity in the second quarter and $28.5 million in the first half of 2004 compared to $14 million and $29 million for the same periods in 2003.

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 to minimize 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 $8.7 million in the second quarter and $25.8 million in the first half of 2004, as compared to $17.1 million and $33.8 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 the Company 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.

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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.

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, 2004. 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, 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; th e two provisions are stayed until the PSB issues its Final Accounting Order.

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 $5.9 million in the second quarter and $11.5 million in the first half of 2004. This compares to purchases of $5.5 million in the second quarter and $9.9 million in the first half 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, the Company, 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 issued 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, the residents of the Town of Milton opposed the dam's removal. The PSB has scheduled more public hearings later in 2004. 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 July 12, 2004, and is expected to take approximately seven weeks. 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 June 30, 2004, we had regulatory assets of about $6.5 million related to Maine Yankee and $2.5 million related to Connecticut Yankee. These estimated costs are being collected from our customers through existing retail and wholesale rate tariffs. At June 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.

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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. 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: 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 the Company's customers through existing rates.

Our estimated aggregate obligation related to Connecticut Yankee is about $13 million. The timing, amount and outcome of the matters 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 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, challenging the legal availability of the remedies requested by Bechtel. 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 scheduled an August 26, 2004 hearing on the legal availability of the remedies requested by Bechtel. A hearing on the other PJR issues, if necessary, has been scheduled to begin on O ctober 19, 2004.

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Attorney General. 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 June 30, 2004, Catamount had interests in nine operating independent power projects located in Rumford, Maine; East Ryegate, Vermont; Hopewell, Virginia; Rupert and Glenns Ferry, Idaho; Nolan County, Texas; Thetford, England; Thuringen, Germany; and Mecklenburg-Vorpommern, Germany.

     Catamount is focused on developing, owning and operating wind energy projects and is continuing to pursue the sale of certain of its interests in non-wind electric generating assets. Depending on prices, capital and other requirements, Catamount will also entertain offers for the purchase of any of its remaining non-wind electric generating assets. Proceeds from the sales will be reinvested in the development of new wind projects and the acquisition of existing wind projects. Additionally, 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 Wales 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.

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Catamount Results
Catamount recorded earnings of less than $0.1 million in the second quarter and $0.6 million in the first half of 2004, compared to $0.2 million and $0.1 million for the same periods in 2003. The increased earnings in 2004 are primarily due to fees associated with its United Kingdom development efforts and lower operating costs, offset by lower equity earnings. 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 which will be recorded in the third quarter of 2004.

In May 2002, Rupert and Glenns Ferry were issued an Events of Default notice by their lender. Steam host restructurings in 2002 cured most of the events of default. Rupert cured its remaining events of default in March 2003 and Glenns Ferry cured its remaining events of default in June 2004.

Eversant At June 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 second quarter and $0.2 million for the first half of 2004, compared to $0.1 million and $0.2 million for the same periods in 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, dividends, 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.

In the first quarter of 2004, taxes on income included a $5.9 million benefit related to a SFAS No. 5 loss accrual as described in Discontinued Operations above.

On April 16, 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.

RECENT ACCOUNTING PRONOUNCEMENTS

See Note 1 to the accompanying Condensed Consolidated Financial Statements.

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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 June 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 June 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 June 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 5.	Other Information.
	(a)	Herbert H. Tate resigned from the Company's Board of Directors effective July 5, 2004.
Item 6.	Exhibits and Reports on Form 8-K.
	(a)	List of Exhibits
		4-63	Forty-Fourth Supplemental Indenture, dated as of June 15, 2004 amending and restating the Company's Indenture of Mortgage dated as of October 1, 1929.
		4-64	Forty-Fifth Supplemental Indenture, dated as of July 15, 2004 and directors' resolutions establishing the Series SS and Series TT Bonds and matters connected therewith.
		4-65	Form of Bond Purchase Agreement dated as of July 15, 2004 relating to Series SS and Series TT Bonds.
		A 10.100	Performance Share Incentive Plan dated effective January 1, 2004.
		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.
	(b)	Item 5. Item 5. Items 7. & 12.	On June 1, 2004 the Company furnished a Current Report on Form 8-K under Item 5, Other Events and Regulation FD Disclosure, announcing that it priced First Mortgage Bonds intended to refinance and replace its Second Mortgage Bonds. No other Current Reports on Form 8-K were filed during the first quarter of 2004; however On July 15, 2004 the Company furnished a Current Report on Form 8-K under Item 5, Other Events and Regulation FD Disclosure a press release announcing the Company's response to State inquiry into the possibility of lowering rates and expenses and filed for a five percent rate increase effective April 2005. On July 26, 2004, the Company furnished a Current Report on Form 8-K under Items 7 and 12, Financial Statements and Exhibits and Results of Operations and Financial Condition, respectively, announcing the results of the Company's operations for the second quarter ended June 30, 2004.
		Item 5.	On August 3, 2004, the Company furnished a Current Report on Form 8-K under Item 5, Other Events and Regulation FD Disclosure announcing the sale of $20 million of 5.00% and $55 million of 5.72% First Mortgage Bonds with the proceeds used to repay in full the Company's $75 million of 8.125% Second Mortgage Bonds.

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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 August 5, 2004

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EXHIBIT INDEX
Exhibit Number	Exhibit Description
4-63	Forty-Fourth Supplemental Indenture, dated as of June 15, 2004 amending and restating the Company's Indenture of Mortgage dated as of October 1, 1929.
4-64	Forty-Fifth Supplemental Indenture, dated as of July 15, 2004 and directors' resolutions establishing the Series SS and Series TT Bonds and matters connected therewith.
4-65	Form of Bond Purchase Agreement dated as of July 15, 2004 relating to Series SS and Series TT Bonds.
A 10.100	Performance Share Incentive Plan dated effective January 1, 2004.
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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Contractual Obligations	Payments Due by Period (in millions)
Contractual Obligations	Total	Remainder of 2004	2005 & 2006	2007 & 2008	Thereafter
Long-term Debt - utility (a)	$126.8	$75.0	-	$3.0	$48.8
Redeemable Preferred Stock	8.0	-	$2.0	2.0	4.0
Purchased Power Contracts (b)	1,379.3	68.2	279.2	281.9	750.0
Capital Lease	11.3	0.6	2.2	1.8	6.7

Total Contractual Obligations	$1,525.4	$143.8	$283.4	$288.7	$809.5

(a) See Financing discussion below. (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		$.40

Year over Year Effects on Earnings:
Lower purchased power costs	.15
IRS tax settlement received in the second quarter of 2004	.09
Higher retail and firm sales	.03
Higher other operating revenue	.01
Higher other costs	(.06)
Catamount - lower earnings	(.02)
RS-2 power contract termination - no sales in 2004	(.12)
Lower resale sales	(.21)
Subtotal		(.13)

2004 Earnings per diluted share		$.27

2003 Earnings per diluted share		$.79

Year over Year Effects on Earnings:
Higher retail and firm sales	.14
IRS tax settlement received in the second quarter of 2004	.09
Higher other operating revenue	.04
Catamount higher earnings	.04
Higher resale sales	.02
Lower other costs	.01
Higher purchase power costs - excluding SFAS No. 5 loss accrual	(.04)
Discontinued operations - 2003	(.06)
RS-2 power contract termination - no sales in 2004	(.26)
Subtotal		(.02)

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		$1.09

	Three Months Ended June 30
(dollars in thousands)	2004		2003
	mWh	Amount	mWh	Amount

Energy	550,926	$24,179	648,289	$27,370
Capacity:
Capacity purchases		10,186		10,125
SFAS No. 5 loss accrual		-		-
Total purchased power		$34,365		$37,495

	2004 vs. 2003
	Second Quarter	Year to date
*Utility Business*
IRS tax settlement	0.9	0.9
Interest income	0.4	0.5
Cash surrender value of life insurance policies	(0.2)	(0.1)
Other	(0.5)	(0.6)
Unregulated Businesses
Catamount revenues and expenses	(0.3)	0.6
Total Variance	$0.3	$1.3