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

For the quarterly period ended     March 31, 2005    

or

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

For the transition period from _______ to _______

Commission file number     1-8222   

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

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

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

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

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

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

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

      Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. As of April 30, 2005 there were outstanding 12,247,369 shares of Common Stock, $6 Par Value.

Page 1 of 48

CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Form 10-Q - 2005

Table of Contents

Page 2 of 48

Page 4 of 48

Page 6 of 48

Page 8 of 48

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.; Custom Investment Corporation, a passive investment subsidiary; and Connecticut Valley Electric Company Inc. ("Connecticut Valley"), which distributed and sold electricity in parts of New Hampshire. On January 1, 2004, Connecticut Valley completed the sale of substantially all of its plant assets and franchise. See Note 11 - Discontinued Operations.

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

Regulatory Accounting The Company is regulated by the Vermont Public Service Board ("PSB"), the Connecticut Department of Public Utility and Control and the Federal Energy Regulatory Commission ("FERC"), with respect to rates charged for service, accounting, financing and other matters pertaining to regulated operations. The Company prepares its financial statements in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71, Accounting for the Effects of Certain Types of Regulation ("SFAS No. 71"), for its regulated Vermont service territory and FERC-regulated wholesale business. On March 29, 2005, the PSB issued its Order ("Rate Order") on the rate investigation and the Company's request for a rate increase, described in Note 9 - Retail Rates. Although, the Rate Order had a significant unfavorable effect on the Company's financial position and results of operations for the period ended March 31, 2005, the Company's regulated business continues to meet the criteria for accounting under SFAS No. 71. Based on a current evaluation of the factors and conditions expected to impact future cost recovery, management believes future recovery of its regulatory assets in the State of Vermont for its retail and wholesale businesses is probable.

In the event that the Company no longer meets the criteria under SFAS No. 71 and there is not a rate mechanism to recover these costs the accounting impact would be an extraordinary charge to operations of about $26.3 million pre-tax as of March 31, 2005. See Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits for additional information.

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

Page 9 of 48

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

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

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

Stock-Based Compensation The Company applies Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees ("APB 25"), and related Interpretations in accounting for its stock option plans and follows the disclosure requirements of SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of SFAS No. 123. The Company did not grant stock options during the three months ended March 31, 2005 and 2004, therefore there is no difference in net income or per share amounts for SFAS No. 123 disclosure purposes.

Page 10 of 48

Earnings Per Share ("EPS") The Condensed Consolidated Statement of Income includes 'basic' and 'diluted' per share information. Basic EPS is calculated by dividing net income, after preferred dividends, by the weighted-average common shares outstanding for the period. Diluted EPS follows a similar calculation except that the weighted-average common shares is increased by the number of potentially dilutive common shares. Since the Company incurred a loss in the first quarter of 2005, the potentially dilutive common shares are not included in the computation of diluted EPS. Also, unvested restricted stock is only included in the computation of diluted shares as they are contingent upon vesting. The table below provides a reconciliation of (loss) earnings available for common stock and average basic and diluted common shares (in thousands, expect share information):

At March 31, 2005 the calculation of diluted EPS excludes 162,891 shares of common stock issuable upon exercise of stock options and 5,892 of unvested restricted shares, because their inclusion in the calculation would be anti-dilutive.

At March 31, 2004, all outstanding stock options were included in the computation of diluted shares because the exercise prices were lower than the average market prices of the common shares in the period.

Assets Held for Sale In the first quarter of 2005, the Company entered into a Purchase and Sale Agreement to sell its property located in Ascutney, Vermont. The sale includes the land and service center building which is no longer being used by the Company. This asset is classified as held for sale on the Condensed Consolidated Balance Sheet in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Regulatory accounting treatment related to the sale of property requires that sale costs and any related loss or gain be offset in accumulated depreciation. The net book value of the property was about $0.4 million at March 31, 2005. The Company expects that any resulting gain or loss on the sale will be a nominal amount.

Investments in Marketable Securities  The Company accounts for investments in marketable equity and debt securities in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities ("SFAS No. 115"). At March 31, 2005, all of the Company's marketable securities were classified as available-for-sale and reported at fair value. Unrealized gains and losses are reported as a component of accumulated other comprehensive income (loss), net of tax, in common stock equity. The carrying cost of debt securities is adjusted for amortization of premiums and accretion of discounts from the date of purchase to maturity.

The Company evaluates the carrying value of its investments on a quarterly basis, or when events and circumstances warrant, determining whether a decline in fair value should be considered other-than-temporary. The carrying value is considered impaired when the anticipated fair value, based on cash flow forecasts is less than the carrying value of each investment. In that event, a realized loss is recognized based on the amount by which the carrying value exceeds the fair value of the investment. The Company applies the method our investment managers use for determining cost basis in computing realized gains and losses on the sale of its available-for-sale securities. These realized gains and losses are included in other income or deductions. See Note 6 - Investment Securities.

Cash, Cash Equivalents and Restricted Cash The Company considers all liquid investments with an original maturity of three months or less when acquired to be cash and cash equivalents. Restricted cash at December 31, 2004 was related to mandatory redeemable preferred stock and included $1.0 million for the mandatory sinking fund payment and $1.0 million for the optional sinking fund payment. These payments to the Preferred Shareholders were effective January 1, 2005.

Page 11 of 48

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

Non-cash Operating, Investing and Financing Activities For additional information regarding non-cash activities, see Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits, Note 9 - Retail Rates and Note 10 - Commitments and Contingencies.

Reclassifications The Company will record reclassifications to the financial statements of prior years when considered necessary or to conform to current-year presentation. The reclassification of auction rate securities from cash and cash equivalents to short-term available-for-sale securities in the December 31, 2004 balance sheet resulted in a decrease of $24.5 million to the ending cash and cash equivalents line items as previously presented in the Condensed Consolidated Statement of Cash Flows for the three-month period ended March 31, 2004. The reclassifications also impacted cash flows used in investing activities and net increase in cash and cash equivalents by $9.9 million for the quarter ended March 31, 2004. There was no impact on net income, cash flow from operations, total assets or covenants as a result of this reclassification.

Recent Accounting Pronouncements

SFAS No. 123R: In December 2004, the Financial Accounting Standards Board ("FASB") issued SFAS No. 123R, Share-Based Payments ("SFAS No. 123R"), which replaces SFAS No. 123 and supersedes, APB 25. SFAS No. 123R requires that compensation cost relating to share-based payment transactions be recognized in the financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. The Company has not elected to early adopt SFAS No. 123R. In April 2005, the SEC approved a rule that delayed the effective date of SFAS No. 123R for public companies. As a result, SFAS No. 123 will be effective for the Company in the first quarter of 2006 and will apply to all of the Company's outstanding unvested share-based payment awards as of January 1, 2006 and all prospective awards.

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

SFAS No. 151: In December 2004, FASB issued SFAS No. 151, Inventory Costs, ("SFAS No. 151") which clarifies the treatment of abnormal freight, handling, and waste costs associated with inventories. This statement requires that abnormal freight, handling, and waste costs be recognized as current expenses and is effective for fiscal years beginning after June 15, 2005. The Company does not believe that adoption of SFAS No. 151 will have a material impact on its financial position or results of operations.

FIN 47: In March 2005, FASB issued FIN 47, Accounting for Conditional Asset Retirement Obligations, which clarifies that the term 'conditional asset retirement obligation' as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 will be effective for the Company in the fourth quarter of 2005. The Company has not determined the impact, if any, FIN 47 will have on its financial position or results of operations and cash flows.

Page 12 of 48

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

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

VELCO bills the Company on a monthly basis for transmission and administrative costs associated with power and transmission services; these billings include various credits such as those from ISO-New England under the NEPOOL Open Access Transmission Tariff ("NOATT"). VELCO's monthly billings amounted to $0.8 million in the first quarter of 2005 and $3.0 million for the same period in 2004, and are reflected as production and transmission expenses in the Condensed Consolidated Statements of Income. In the first quarter of 2004, VELCO also billed the Company about $1.7 million for its share of NOATT charges. These charges are now billed directly to the Company from ISO-New England. Accounts payable to VELCO amounted to $5.2 million at March 31, 2005 and $4.8 million at December 31, 2004.

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 10 - Commitments and Contingencies.

NOTE 3 - NON-UTILITY INVESTMENTS

Catamount: Catamount invests in unregulated energy generation projects primarily in the United States and United Kingdom. As of March 31, 2005, Catamount had interests in six operating independent power projects located in Rumford, Maine; East Ryegate, Vermont; Nolan County, Texas; Thuringen, Germany and Mecklenburg-Vorpommern, Germany.

As of March 31, 2005, Catamount had Notes Receivable of $13.2 million, net of allowances of $0.7 million. Notes Receivable is comprised of a $12.9 million note, net of allowance of $0.4 million, associated with the development of a wind site located in Nolan County, Texas, and a $0.3 million note, which has been fully reserved, related to the sale of a development project in the United States.

Page 13 of 48

Catamount recorded first quarter 2005 earnings of $0.2 million compared to first quarter 2004 earnings of $0.6 million. Catamount or its wholly owned subsidiaries provide certain management, accounting and other services to certain entities in which Catamount holds an equity interest. The fees are designed to recover actual costs or are agreed upon by other equity investors in these entities. Catamount's revenues (included in Other Income on the Condensed Consolidated Statements of Income) include billings of $0.1 million in the first quarters of 2005 and 2004. At March 31, 2005 and December 31, 2004 Accounts Receivable for these billings amounted to $0.6 million, of which $0.5 million was reserved.

Information regarding certain of Catamount's investments follows.

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

Rumford Cogeneration ("Rumford") In the first quarter of 2005, Catamount determined that its equity investment in Rumford was impaired; however the impairment was determined to be temporary. Management's assessment was based on the fact that the electric energy rate, a critical component in determining whether an impairment has occurred, is currently being negotiated between the affected parties. Catamount prepared several scenarios based on varying electric energy prices and other assumptions which resulted in a range of possible outcomes ranging from no impairment to an impairment of $1.7 million. At this time, Management does not believe any one scenario has a higher probability of occurrence than the others and therefore has concluded the impairment is temporary.

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

Eversant: As of March 31, 2005, Eversant had a $1.4 million equity investment, representing a 12 percent ownership interest in The Home Service Store Inc. ("HSS"). HSS has established a network of affiliate contractors who perform home maintenance repair and improvements for its members. Eversant accounts for this investment on the cost basis.

Under SFAS No. 71, the Company accounts for certain transactions in accordance with permitted regulatory treatment such that regulators may permit incurred costs, typically treated as expenses by unregulated entities, to be deferred and expensed in future periods when recovered in future revenues. In the Rate Order, the PSB determined the annual revenue requirement for the period April 1, 2004 through March 31, 2005, and established that rates during that period included recovery of certain deferred charges and regulatory liabilities. As a result, in March 2005, the Company adjusted certain deferred charges and credits, and began required amortizations of certain regulatory assets and regulatory liabilities beginning April 1, 2004. Additionally, certain deferred charges were reclassified to regulatory assets to reflect rate recovery.

Net regulatory assets, deferred charges and other deferred credits decreased $12.6 million from December 31, 2004 to March 31, 2005. That decrease is primarily attributed to the Rate Order, which resulted in a $15.3 million decrease in certain regulatory assets, deferred charges and deferred credits. The corresponding offset is a $15.3 million pre-tax charge to earnings in March 2005. See Note 9 - Retail Rates for additional information.

Page 14 of 48

A summary of net regulatory assets, deferred charges and deferred credits follows (in thousands):

1. Pursuant to the Rate Order, certain regulatory assets related to C&LM programs were reduced, resulting in a $0.3 million pre-tax charge to earnings in March 2005. Other costs are being amortized over a two-year period beginning April 1, 2004.

Estimated decommissioning costs related to the Company's equity investments in Maine Yankee, Connecticut Yankee and Yankee Atomic. See Note 10 - Commitments and Contingencies for additional information related to nuclear plant decommissioning. These costs are being recovered in retail rates. The Rate Order required the following: 1) previously deferred incremental dismantling costs for the twelve months ended March 31, 2005 be expensed to reflect rate recovery during that time; 2) Yankee Atomic incremental dismantling costs already paid by the Company be amortized over a three-year period ($0.5 million annually) beginning April 1, 2004, and 3) beginning April 1, 2006, for each plant, differences between actual decommissioning cost payments and amounts included for rate recovery, be deferred until the Company's next rate proceeding.

 

 

 

 

Page 15 of 48

In March 2005, the Company recorded a $2.4 million pre-tax charge to earnings related to Connecticut Yankee ($0.2 million) and Yankee Atomic ($2.2 million) deferred incremental dismantling costs, to reflect adjustments required in the Rate Order. This included a $1.9 million charge to purchased power expense and a $0.5 million charge to operating expense. Deferred charges were also reclassified to regulatory assets, to reflect rate recovery.

2. Regulatory asset related to deferred incremental Vermont Yankee sale costs (excluding incremental income tax expense) that resulted from the difference between costs that the Company would have incurred had it not pursued the sale and those it incurred by pursuing the sale. Pursuant to the Rate Order, these costs are being amortized over a three-year period ($2.0 million annually) beginning April 1, 2004.

In March 2005, the Company recorded a $2.5 million pre-tax charge to earnings to reflect adjustments required in the Rate Order. This included a $2.0 million charge to operating expense and a $0.5 million reduction of interest income related to adjusted carrying costs. Deferred charges were also reclassified to regulatory assets, to reflect rate recovery.

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

In March 2005, the Company recorded a $1.6 million pre-tax charge to earnings to reflect adjustments required in the Rate Order. This included a $0.9 million charge to operating expense, a $0.4 million charge to other deductions, and a $0.3 million decrease in interest income. Deferred charges were also reclassified to regulatory assets, to reflect rate recovery.

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

 

 

 

 

 

 

Page 16 of 48

Required adjustments to the regulatory liability included: 1) a $12.1 million increase resulting from recalculation of overearnings for the periods 2001 - 2003; 2) a $3.8 million decrease resulting from amortization for April 1, 2004 through March 31, 2005; 3) a $0.3 million decrease related to adjusted carrying costs; and 4) a $3.8 million decrease resulting from reversal of the regulatory liability associated with 2004 utility overearnings. See Note 9 - Retail Rates for additional information.

9. Pursuant to the Rate Order, the Company was required to apply the 2004 gain on the Connecticut Valley asset sale to the benefit of ratepayers through amortizations over a three-year period ($2.2 million annually) beginning April 1, 2004. In March 2005, the Company established a regulatory liability in the amount of $6.6 million pre-tax, per the Rate Order, offset by amortization of $2.2 million. This resulted in a net $4.4 million pre-tax charge to earnings in March 2005. See Note 9 - Retail Rates for additional information.
10. 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 must benefit ratepayers through programs to promote renewable resources.
11. The Rate Order required adjustments to other regulatory liabilities that resulted in a $0.1 million pre-tax charge to earnings. This reflected a requirement that tree trimming and pole treating expenditures below those amounts included in retail rates be deferred as regulatory liabilities and any amounts in excess be recorded as deferred charges. These amounts would then carry forward for use in future years.

NOTE 5 - LONG-TERM DEBT
Utility Substantially all of the Company's utility property and plant is subject to liens under the First Mortgage Bonds. No sinking fund payments are due on long-term debt for 2005 through 2007. Currently, the Company is not in default under any of its debt financing documents.

The Company's long-term debt indentures, letters of credit and Articles of Association contain financial and non-financial covenants. At March 31, 2005, the Company was in compliance with all covenants.

Available-for-sale securities  At March 31, 2005, Current Assets associated with available-for-sale securities increased by $10.2 million and Investments and Other Assets (long-term) decreased by $9.0 million reflecting the Company's intent to liquidate certain available-for-sale securities within one year.

The Company evaluates the carrying value of these investments on a quarterly basis, or when events and circumstances warrant, to determine whether a decline in fair value is considered temporary or other-than-temporary. The Company considers several criteria in evaluating other-than-temporary declines, including 1) length of time and extent to which market value has been less than cost; 2) financial condition and near-term prospects of the issuer; and 3) intent and ability of the Company to retain its investment in the issuer for a period of time sufficient to allow for any anticipated recovery in market value. In the first quarter of 2005, the Company recorded a $0.3 million impairment of certain available-for-sale investments based on its intent to liquidate those securities prior to their original maturity dates. Based upon forecasted cash flow needs, those securities closest to maturity were impaired. Generally, a security close to its maturity date should have less pricing volatility due to interest rate movements than one further from its maturity date.

In the first quarter of 2005, the Company also recorded $0.1 million of realized losses and $0.3 million of debt security premiums amortization to interest income as a deduction from the coupon interest earned on available-for-sale securities.

The unrealized losses on available-for-sale securities shown below, both on an individual and aggregate basis, are minor when compared to the original costs, and are related to securities the Company expects to hold to maturity based on forecasted cash needs. Therefore, such unrealized losses are considered temporary.

Page 17 of 48

Information regarding available-for-sale securities as of March 31, 2005 follows (in thousands):

The following table presents the fair value and gross unrealized losses of the Company's available-for-sale securities, aggregated by investment category and the length of time the securities have been in a continuous loss position, at March 31, 2005 (in thousands):

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

These investments are subject to the requirements of SFAS No. 115, and are recorded at fair value in Investments and Other Assets on the Condensed Consolidated Balance Sheets. The unrealized losses on the decommissioning trust fund are minor when compared to their original cost; therefore, they are considered temporary. At March 31, 2005, losses on equity securities have been in a continuous loss position for less than 12 months. The fair value of these investments is summarized below (in thousands):

Page 18 of 48

The following table presents the fair value and gross unrealized losses of these investments, aggregated by investment category and the length of time the securities have been in a continuous loss position, at March 31, 2005 (in thousands):

Information related to the fair value of debt securities at March 31, 2005 follows (in thousands):

Pension costs and cash funding requirements are expected to increase in future years. At March 31, 2005, the fair value of Pension Plan trust assets was $62.8 million. At December 31, 2004, the fair value of Pension Plan trust assets was $64.2 million.

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

The Medicare Part D subsidy is about $0.1 million in the first quarter of 2005 and is expected to be about $0.3 million for the year 2005.

Rate Order: In March 2005, the Company recorded a $21.8 million pre-tax, or $11.2 million after-tax, charge to utility earnings due to the Rate Order. The related $10.0 million income tax benefit included in taxes on income also includes a $1.6 million favorable impact resulting from a higher projected 2005 income tax rate. The remaining $0.6 million benefit is included in Benefit (provision) for income taxes.

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.

Page 19 of 48

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

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

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

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

On March 29, 2005, the PSB issued its Order ("Rate Order") on the rate investigation and the Company's request for a rate increase. The PSB concluded that the Company's rates were higher than is just and reasonable, and must be reduced. In its Order, the PSB determined the annual revenue requirement beginning April 1, 2004, established rates retroactive to April 7, 2004 and established new rates beginning April 1, 2005. The Rate Order included, among other things, the following: 1) a 1.88 percent rate reduction beginning April 1, 2005; 2) a $3.3 million dollar refund to customers, 3) a 10 percent return on equity (reduced from 11 percent); and 4) a requirement that the gain resulting from the 2004 sale of Connecticut Valley's assets be applied to the benefit of ratepayers to compensate for increased costs. The Company was also required to file a compliance filing by April 1, 2005 and file a new rate design within 90 days of the Rate Order.

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

For accounting purposes, the Rate Order resulted in a $21.8 million, or $11.2 million after-tax, unfavorable effect on utility earnings in March 2005. The primary components of the charge to earnings include: 1) a revised calculation of overearnings for the period 2001 - 2003; 2) application of the gain resulting from the Connecticut Valley sale to reduce costs; 3) a customer refund for over-collections for the period April 7, 2004 through March 31, 2005; and 4) amortization of costs and other adjustments required in the Rate Order. These are described in more detail below (all on a pre-tax basis).

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

 

 

 

Page 20 of 48

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

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

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

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

In March 2005, the Company recorded a $6.6 million charge to operating expense, offset by a regulatory liability, to reflect the amount to be amortized. The Company also recorded amortizations for the twelve-months ending March 31, 2005, which reduced operating expense and the regulatory liability by $2.2 million. In total, this amounted to a net $4.4 million charge to earnings.

3. The Rate Order, with revisions from the PSB's Compliance Order, requires a customer refund amounting to about $6.2 million ($3.3 million after-tax) and carrying costs of $0.3 million based on a lump-sum refund. The refund represents over-collections from customers for April 7, 2004 though March 31, 2005 ($1.7 million is attributed to 2005 and $4.5 million is attributed to 2004). On April 25, 2005, the PSB approved a proposal for a lump-sum refund to customers in June 2005 billings. Additionally, on April 25, 2005, the PSB approved application of the $3.8 million regulatory liability for 2004 overearnings (see discussion of February 18, 2005 Accounting Order above) to the refund liability.

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

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

• a $2.4 million increase in purchased power expense mostly related to expensing of Yankee Atomic incremental dismantling costs and Vermont Yankee 2004 replacement energy costs to reflect rate recovery beginning April 1, 2004;
• a $3.2 million increase in operating expenses mostly related to amortization of Vermont Yankee (non-tax) sale-related costs, Vermont Yankee 2002 fuel rod costs and Yankee Atomic dismantling costs to reflect rate recovery beginning April 1, 2004;
• a $0.8 million decrease in interest income to adjust carrying costs related to Vermont Yankee (non-tax) sale-related costs and Vermont Yankee 2002 fuel rod costs due to rate recovery beginning April 1, 2004;

Page 21 of 48

• a $0.4 million increase in other deductions for disallowance of a portion of Vermont Yankee 2002 fuel rod costs; offset by
• a $0.4 million decrease in other interest expense related to various other adjustments per the Rate Order.

On April 4, 2005, Standard and Poor's Ratings Services placed the Company's 'BBB-' corporate credit rating on CreditWatch with negative implications.

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

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

The Company, DPS and AARP submitted their responses to these motions by April 26, 2005 as required by the PSB. The Company is not able to predict the outcome of these matters at this time.

The table below reflects the unfavorable impacts of the Rate Order on specific line items of the Condensed Consolidated Statement of Income for the first quarter of 2005 on a pre-tax basis (in millions).

Nuclear Investments Nuclear Generating Companies The Company is 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 three of these nuclear plants have been shut down and are undergoing decommissioning. The Company also has a joint-ownership interest in Millstone Unit #3. Its obligations related to these plants are described below.

Maine Yankee, Connecticut Yankee and Yankee Atomic All three companies collect decommissioning and closure costs through wholesale FERC-approved rates charged under power agreements with several New England utilities, including the Company. Historically, the Company's share of these costs has been recovered from its retail customers through PSB-approved rates. Based on the regulatory process, management believes its share of decommissioning and closure costs for each plant will continue to be recovered through the regulatory process. Although, Management believes that these costs will ultimately be recovered from its customers, there is a risk that FERC may not allow full recovery of Connecticut Yankee's increased costs in wholesale rates, as described below. If FERC does not allow these costs to be recovered in wholesale rates, the Company anticipates that the PSB would disallow these costs for recovery in retail rates as well.

The Company's share of Maine Yankee, Connecticut Yankee and Yankee Atomic estimated costs are reflected on the Condensed Consolidated Balance Sheet as regulatory assets and nuclear decommissioning liabilities (current and non-current). These amounts are adjusted when revised estimates are provided by the companies. At March 31, 2005, the Company had regulatory assets of about $5.6 million related to Maine Yankee, $12.1 million related to Connecticut Yankee and $4.7 million related to Yankee Atomic. These estimated costs are being collected from the

Page 22 of 48

Company's customers through existing retail rate tariffs. See Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits, regarding the impacts of the Rate Order.

Maine Yankee, Connecticut Yankee and Yankee Atomic are seeking recovery of fuel storage-related costs stemming from the default of the United States Department of Energy ("DOE") under the 1983 fuel disposal contracts that were mandated by the United States Congress under the High Level Waste Act. All three are parties to a lawsuit against the DOE seeking damages based on the DOE's default. The trial on determination of damages began on July 12 and ended August 31, 2004. Closing arguments were held in January 2005 and final post-trial briefs were filed in February 2005. The Department of Justice submitted a motion to the court during the damage trial arguing that the spent fuel obligations prior to April 1983 should be treated as an offset to any award of damages. The Court's ruling on that matter is expected to be issued with its overall ruling in the case, which is expected by the end of 2005. None of the plants has included any allowance for potential recovery of these claims in their FERC-filed c ost estimates.

Maine Yankee: The Company has a 2 percent ownership interest in Maine Yankee. Beginning November 1, 2004, Maine Yankee's billings to sponsor companies have been based on its September 16, 2004, FERC approved settlement, which provides for recovery of Maine Yankee's forecasted costs of providing service through a formula rate contained in its power contracts through October 31, 2008 and replenishment of the DOE Spent Fuel Obligation through collections from November 2008 through October 2010.

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-filed rates effective February 1, 2005, for collection through 2010. Prior to February 1, 2005, costs were based on FERC-approved rates that became effective September 1, 2000, for collection through 2007.

Connecticut Yankee is currently involved in litigation related to a contract dispute. Also in 2004, Connecticut Yankee filed a rate application with FERC. These matters are discussed in more detail below.

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

Page 23 of 48

Yankee Atomic: The Company has a 3.5 percent ownership interest in Yankee Atomic. Costs billed by Yankee Atomic are based on an April 4, 2003 FERC filing, in which FERC approved the resumption of billings starting June 2003 for a recovery period through 2010.

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

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

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

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

As of March 31, 2005, a $6.0 million reserve for environmental matters is recorded on the Condensed Consolidated Balance Sheet. At December 31, 2004, the reserve was $6.1 million. The reserve represents Management's best estimate of the cost to remedy issues at these sites.  There is no pending or threatened litigation regarding other sites with the potential to cause material expense. No government agency has sought funds from the Company for any other study or remediation.

Catamount In November 2004, Catamount entered into an agreement with a third-party developer for the purchase of wind turbines for a joint development project. Pursuant to the agreement, Catamount made a total of $5.9 million of payments to the turbine supplier in 2004 and a $5.9 million payment in March 2005. The turbine supply agreement calls for a payment of $14.8 million in September 2005, with the remaining contract amount of $32.5 million due based on milestones established in the agreement. When the Sweetwater 3 construction financing is complete in early May 2005, the September 2005 and remaining contract amount will be assumed by the Sweetwater 3 project, pursuant to the construction financing agreement.

Page 24 of 48

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

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

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

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

The accounting policies of operating segments are the same as those described in the summary of significant accounting policies. Intersegment revenues include revenues for support services, including allocations of software systems and equipment, to Catamount and Eversant. Financial information by industry segment for the first quarters of 2005 and 2004 is as follows (in thousands):

1. See Note 2 herein for CV's investments in affiliates.
2. See Note 3 herein for CV's investment in non-utility affiliates.
3. See Note 9 herein for Retail Rates.

Item 2.  Management's Discussion and Analysis of Financial Condition and Results of Operations.

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

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

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

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

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

On March 29, 2005, the PSB issued its Order ("Rate Order") on the rate investigation and our request for a rate increase. The PSB concluded that our rates were higher than is just and reasonable, and must be reduced. See Retail Rates discussion below for additional information. The Rate Order has had a significant impact on our first quarter 2005 results, and will impact this year's annual earnings to a large degree. The immediate impact to earnings is a $21.8 million, or $11.2 million after-tax, unfavorable effect on earnings in the first quarter of 2005. In total, we had a first quarter 2005 consolidated loss of $4.6 million, or 39 cents per diluted share of common stock, compared to first quarter 2004 earnings of $10.4 million, or 82 cents per diluted share of common stock. Our first quarter 2005 results compared to the same period in 2004 are explained in detail in Results of Operations below.

Pursuant to the Rate Order our retail rates were reduced by 2.75 percent beginning April 1, 2005, our allowed return on equity was reduced from 11 percent to 10 percent, and we are required to refund to customers about $6.5 million, including carry costs, in June 2005. In the near term we have sufficient cash on hand, including available-for-sale securities, to maintain operations. However without a combination of ongoing cost reductions and a rate increase within the next eighteen months, our ongoing liquidity will be greatly impacted. Currently, we are seeking to obtain a $20 to $25 million line of credit to help ensure liquidity is maintained over the near-term. Additionally, as a result of the Rate Order, S&P placed our corporate credit rating on Creditwatch with negative implications. These matters are discussed in more detail in Liquidity and Capital Resources below.

We are in the process of implementing a comprehensive action plan to address the issues before us. Management has also identified opportunities for cost reductions totaling $0.75 million in 2005. At the same time, we are in the process of identifying ongoing cost cuts to provide longer-term financial stability for the utility in 2006 while maintaining customer service and reliability. At some point, given inflationary cost pressures, we will have to file a new rate case.

Page 27 of 48

Given the Rate Order outcome, we have decided not to make any additional investments in Catamount this year. However, 2005 is a critical year in Catamount's wind development strategy. To ensure Catamount can achieve its development goals, we extended a bridge loan up to $14.8 million to continue construction of the 135-megawatt Sweetwater 3 project in Texas. This project is expected to reach financial close in early May 2005.

Catamount is pursuing a loan secured by cash flow from its Sweetwater equity investments so that it is able to repay the loan this year. In addition, Catamount is seeking an equity partner to pursue future growth opportunities. See discussion of Liquidity and Capital Resources and Diversification below for additional information.

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

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

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

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

On March 29, 2005, the PSB issued its Order ("Rate Order") on the rate investigation and our request for a rate increase. The PSB concluded that our rates were higher than is just and reasonable, and must be reduced. In its Order, the PSB determined the annual revenue requirement beginning April 1, 2004, established rates retroactive to April 7, 2004 and established new rates beginning April 1, 2005. The Rate Order included, among other things, the following: 1) a 1.88 percent rate reduction beginning April 1, 2005; 2) a $3.3 million dollar refund to customers, 3) a 10 percent return on equity (reduced from 11 percent); and 4) a requirement that the gain resulting from the 2004 sale of Connecticut Valley's assets be applied to the benefit of ratepayers to compensate for increased costs. We were also required to file a compliance filing by April 1, 2005 and file a new rate design within 90 days of the Rate Order.

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

For accounting purposes, the Rate Order resulted in a $21.8 million, or $11.2 million after-tax, unfavorable effect on utility earnings in March 2005. The primary components of the charge to earnings include: 1) a revised calculation of overearnings for the period 2001 - 2003; 2) application of the gain resulting from the Connecticut Valley sale to reduce costs; 3) a customer refund for over-collections for the period April 7, 2004 through March 31, 2005; and 4) amortization of costs and other adjustments required in the Rate Order. These are described in more detail below (all on a pre-tax basis).

Page 28 of 48

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

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

In March 2005, we recorded a net $8.3 million charge to earnings. This included a $10.8 million charge to operating expense and $1.3 million to interest expense, offset by amortization of $3.8 million.

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

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

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

3. The Rate Order, with revisions from the PSB's Compliance Order, requires a customer refund amounting to about $6.2 million ($3.3 million after-tax) and carrying costs of $0.3 million based on a lump-sum refund. The refund represents over-collections from customers for April 7, 2004 though March 31, 2005 ($1.7 million is attributed to 2005 and $4.5 million is attributed to 2004). On April 25, 2005, the PSB approved a proposal for a lump-sum refund to customers in June 2005 billings. Additionally, on April 25, 2005, the PSB approved application of the $3.8 million regulatory liability for 2004 overearnings (see discussion of February 18, 2005 Accounting Order above) to the refund liability.

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

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

• a $2.4 million increase in purchased power expense mostly related to expensing of Yankee Atomic incremental dismantling costs and Vermont Yankee 2004 replacement energy costs to reflect rate recovery beginning April 1, 2004;
• a $3.2 million increase in operating expenses mostly related to amortization of Vermont Yankee (non-tax) sale-related costs, Vermont Yankee 2002 fuel rod costs and Yankee Atomic dismantling costs to reflect rate recovery beginning April 1, 2004;

Page 29 of 48

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

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

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

We, the DPS and AARP submitted responses to these motions by April 26, 2005 as required by the PSB. If any of the motions are successful, it could result in a change in both the refund and rate decrease amounts. We expect the PSB to respond to this motion in May 2005. We are also evaluating an appeal of the Rate Order with the Vermont Supreme Court, and will reach a conclusion on that course of action after the PSB responds to the Motions for Reconsideration. We are not able to predict the outcome of these matters at this time.

The table below reflects the unfavorable impacts of the Rate Order on specific line items of the Condensed Consolidated Statement of Income for the first quarter of 2005 on a pre-tax basis (in millions).

LIQUIDITY AND CAPITAL RESOURCES

At March 31, 2005, we had cash and cash equivalents of $22.7 million and working capital of $60.1 million. During the first three months of 2005, cash and cash equivalents increased by $10.9 million. The increase resulted from the following:

At March 31, 2005, investments in available-for-sale securities included $29.5 million with maturities from 90 days up to one year and $12.9 million with maturities greater than one year.

Page 30 of 48

VELCO:  We are considering continued investments in Vermont Electric Power Company's ("VELCO") planned transmission upgrades. Our investments in VELCO will maintain VELCO's common equity at 25 percent of its total capitalization. VELCO will require additional equity capital beyond 2005 in order to finance all of the proposed transmission upgrades and we will consider additional investments in VELCO at that time. We may invest about $6.0 million in the third quarter of 2005. In total, our investments in VELCO could amount to between $30 million and $35 million through 2007. Our investment plans in VELCO are subject to change due to liquidity deterioration resulting from the Rate Order.

Catamount:  Catamount has sufficient cash flow to cover its ongoing operating expenses. In April 2005, to ensure Catamount can achieve its development goals, we extended a bridge loan up to $14.8 million. Additional project investments that will allow Catamount to execute its growth strategy will require third party financing and an equity investor. We do not plan to make investments in Catamount for the foreseeable future.

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

We believe that cash on hand, including available-for-sale securities, and cash flow from operations will be sufficient to fund our business for the near term, although, Vermont utility cash flow from operations will decrease in 2005 when compared to 2004. 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.

Financing
Utility Based on outstanding debt at March 31, 2005, no principal payments are due on long-term debt from 2005 through 2007. Substantially all utility property and plant are subject to liens under the First Mortgage Bond indenture. Currently, we are not in default under any of our debt financing documents.

At March 31, 2005, we were in compliance with all covenants related to our various debt agreements, Articles of Association and letters of credit; these agreements contain financial and non-financial covenants.

Currently we are seeking to obtain a $20 to $25 million line of credit to help ensure liquidity is maintained over the near-term.

Non-Utility As part of its wind development efforts, Catamount expects to be an equity participant in a wind farm located in Nolan County, Texas known as Sweetwater 3. Construction close on Sweetwater 3 is expected to occur in early May 2005 and as a result Catamount will be required to post $24.8 million of security, representing Catamount's expected equity contribution, to be maintained in pledged collateral accounts for the construction lender. At construction close, Catamount will be reimbursed by the Sweetwater 3 project for cumulative payments of $11.8 million made through March 2005 under the turbine supply agreement as described below and $0.2 million for other Sweetwater 3 related project costs. Catamount will fund the $24.8 million security with the $12.0 million of reimbursements and $12.8 million from the bridge loan extended by the Company in April 2005.

In November 2004, Catamount entered into an agreement with a third-party developer for the purchase of wind turbines for a joint-development project. Pursuant to the agreement, Catamount made a total of $5.9 million of payments to the turbine supplier in 2004 and a $5.9 million payment in March 2005. The turbine supply agreement calls for a payment of $14.8 million in September 2005, with the remaining contract amount of $32.5 million due based on milestones established in the agreement. When the Sweetwater 3 construction financing is complete, the September 2005 and remaining contract amount will be assumed by the Sweetwater 3 project, pursuant to the construction financing agreement.

Catamount has solicited offers from selected financial institutions for a credit facility to be secured by its Sweetwater equity investments. Catamount expects to close on a facility in the second quarter of 2005 and expects to use the proceeds to payoff the $12.8 million bridge loan that we extended to Catamount in April 2005. While Catamount expects to close on a credit facility in the second quarter of 2005, there can be no assurance that Catamount will be successful in securing a credit facility in the desired timeframe. In addition, Catamount is seeking capital from an equity investor or partner in 2005, and a portion of those proceeds could be used to fully repay the bridge loan.

Page 31 of 48

Credit Ratings
Following the rate decision, Standard & Poor's Ratings Services ("S&P") placed our corporate credit rating on "CreditWatch with negative implications." S&P said that it expects to resolve the CreditWatch listing once we adjust our plans for future capital expenditures and operating and maintenance expenditures in light of the rate reduction. While Fitch Ratings ("Fitch") did not take any immediate action, they also expressed concern about this decision.

Our current corporate credit rating with S&P is BBB-. Our first mortgage debt is rated at BBB+ by both S&P and Fitch. In general, a downgrade would increase our borrowing costs and could hamper our operational flexibility by restricting access to capital and imposing additional requirements to provide performance assurance associated with certain power purchase and sale transactions. We believe that we have sufficient liquidity to meet the performance assurance requirements as described below if the need arises. A downgrade would also increase the costs of our three letters of credit and our vehicle lease costs about $0.1 million.

Currently, we are subject to performance assurance requirements associated with our power purchase and sale transactions through ISO-New England under the Financial Assurance Policy for NEPOOL members. While we are generally a net seller to ISO-New England, in limited circumstances, we must post collateral if the net amount owed exceeds our credit limit at ISO-New England. A Company's credit limit is calculated as a percentage, based on its credit rating, of its net worth. At our current credit rating of BBB-, our credit limit with ISO-New England is about $2.7 million. We have not had to post any collateral with ISO-New England in 2005. If we are downgraded to below investment grade status, our credit limit with ISO-New England will go to zero and we will be required to post collateral for all net purchase transactions. Based on recent trading experience, we estimate that we could be required to post about $3.0 million of collateral with ISO-New England if we were to be in a net purchase position w ith ISO-New England after being downgraded to below investment-grade status.

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

At March 31, 2005, we were also selling power in the wholesale market pursuant to two third-party contracts. Under both of these contracts, we would be required to post collateral if downgraded below investment-grade status, but only if required to do so by the counterparties. If downgraded, we estimate that we could be required to post collateral of up to about $11.0 million under these two contracts, based on current forward market prices. Depending on the difference between the contract price and the market price of power, this estimate could increase or decrease accordingly.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our financial statements are prepared in accordance with accounting principles generally accepted in the United States ("GAAP"), requiring us to make estimates and judgments that affect reported amounts of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of the Condensed Consolidated Financial Statements. See Critical Accounting Policies and Estimates in Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report filed on Form 10-K for a discussion of the estimates and judgments necessary in our accounting for regulation, unregulated business, revenues, income taxes, loss accruals, pension and postretirement benefits and other matters. The following is an update to the 2004 Form 10-K.

Regulation We prepare our financial statements in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71, Accounting for the Effects of Certain Types of Regulation ("SFAS No. 71"), for our regulated Vermont service territory and FERC-regulated wholesale business. Although the Rate Order had a significant unfavorable effect on our financial position and results of operations for the period ended March 31, 2005, our regulatory business continues to meet the criteria for accounting under SFAS No. 71. Based on a current evaluation of the factors and conditions expected to impact future cost recovery, Management believes future recovery of its regulatory assets in the State of Vermont for its retail and wholesale businesses is probable.

If we determine that the Company no longer meets the criteria under SFAS No. 71 and there is not a rate mechanism to recover these costs, the accounting impact would be an extraordinary charge to operations of about $26.3 million pre-tax as of March 31, 2005.

Page 32 of 48

Unregulated Business Catamount evaluates the carrying value of its investments on a quarterly basis, or when events and circumstances warrant. The carrying value is considered impaired when the anticipated fair value, based on undiscounted cash flows, is less than the carrying value of each investment. In that event, a loss is recognized based on the amount by which the carrying value exceeds the fair value of the investment.

In the first quarter of 2005, Catamount determined that its equity investment in Rumford Cogeneration Company ("Rumford") was impaired; however the impairment was determined to be temporary. Management's assessment was based on the fact that the electric energy rate, a critical component in determining whether an impairment has occurred is currently being negotiated between the affected parties. Catamount prepared several scenarios based on varying electric energy prices and other assumptions which resulted in a range of possible outcomes from no impairment to an impairment of $1.7 million. At this time, Management does not believe any one scenario has a higher probability of occurrence than the others and therefore has concluded the impairment is temporary. Catamount also determined that first quarter 2005 equity earnings from its German wind projects were impaired by an amount of less than $0.1 million based on a non-binding offer from a third party to purchase the projects. There were no equity in vestment impairments in the first quarter of 2004.

Investments in Marketable Securities We account for investments in marketable equity and debt securities in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities ("SFAS No. 115"). At March 31, 2005, all of our marketable securities were classified as available-for-sale and reported at fair value. Unrealized gains and losses are reported as a component of accumulated other comprehensive income (loss), net of tax, in common stock equity. The carrying cost of debt securities is adjusted for amortization of premiums and accretion of discounts from the date of purchase to maturity.

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

We use several criteria to evaluate other-than-temporary declines, including 1) length of time and the extent to which the market value has been less than cost; 2) financial condition and near-term prospects of the issuer; and 3) our intent and ability to retain the investments for a period of time sufficient to allow for any anticipated recovery in market value. In the first quarter of 2005, we recorded $0.1 million of realized losses and $0.3 million for impairment of certain available-for-sale investments based on our intent to liquidate certain securities prior to their original maturity dates. Based upon forecasted cash flow needs, the security closest to its maturity was chosen. Generally, a security close to its maturity date should have less pricing volatility due to interest rate movements than one further from its maturity date. See Note 6 - Investment Securities for additional information.

Pension and Postretirement Benefits Pension costs were $1.1 million in the first quarter of 2005, of which $0.9 million is reflected in results of operations and the remaining amount was capitalized. This compares to pension costs of $0.8 million in the first quarter of 2004, of which $0.7 million was reflected in results of operations and the remaining amount was capitalized.

Postretirement costs were $0.7 million in the first quarter of 2005, of which $0.6 million is reflected in results of operations and the remaining amount was capitalized. This compares to postretirement costs of $0.8 million in the first quarter of 2004, of which $0.7 million was reflected in results of operations and the remaining amount was capitalized.

Pension costs and cash funding requirements are expected to increase in future years. As of March 31, 2005, the market value of pension plan trust assets was $62.8 million, including $42.3 million in marketable equity securities and $20.5 million in debt securities. Pension plan trust assets were $64.2 million at December 31, 2004, including $44.3 million in marketable equity securities and $19.9 million in debt securities.

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

Page 33 of 48

accrual represented Management's best estimate of the difference between expected future sales revenue, in the wholesale market, for the purchased power that was formerly sold to Connecticut Valley and the cost of purchased power obligations. The estimated life of the power contracts that were in place to supply power to Connecticut Valley extends through 2015.

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

Page 34 of 48

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

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

The $8.5 million decrease in Operating revenues is due to the following factors:

• The retail customer refund reduced revenue by $6.2 million. The Rate Order required a refund to customers for over-collections during the period April 7, 2004 through March 31, 2005. Of the $6.2 million, $1.7 million is attributed to 2005 and $4.5 million is attributed to 2004. See Retail Rates above for additional information.
• Retail and firm sales decreased $1 million due to lower sales volume. These sales are affected by economic and weather conditions. Milder winter weather in 2005 compared to 2004 reduced sales volume by 1.5 percent.
• Other resale sales decreased by $1.3 million primarily due to lower sales volume from forward sale contracts, also lower output from our power resources reduced the amount of excess available for resale.

Page 35 of 48

Purchased Power Most of our power purchases are made under long-term contracts. These contracts, power supply management and nuclear investments are described in more detail in Power Supply Matters below. The primary components of purchased power expense are as follows (in thousands):

The related mWh purchases and unit price from these sources are summarized below:

Purchased power expense decreased $16.1 million in the first quarter of 2005 compared to the same period of 2004 due to the following factors:

• A $14.4 million favorable impact related to the SFAS No. 5 loss accrual that we recorded in the first quarter of 2004. The loss accrual was related to termination of the power contract with Connecticut Valley and represented Management's best estimate of the difference between expected future sales revenue, in the wholesale market, for the purchased power that was formerly sold to Connecticut Valley and the cost of purchased power to be incurred to realize those future sales. In accordance with GAAP, the loss accrual is being amortized on a straight-line basis through 2015, which represents the estimated life of our power contracts that were in place to source the Connecticut Valley power contract. Amortizations reduced purchased power expense by about $0.3 million in the first quarters of 2005 and 2004.
• Long-term purchases decreased $3.3 million primarily related to lower energy prices under the Vermont Yankee purchased power contract, lower Vermont Yankee plant output and lower output from IPPs.
• Short-term purchases decreased about $1 million due to lower volume and lower average prices in 2005.
• Accounting entries related to the Rate Order, described in Retail Rates above, increased purchased power expense by about $2.5 million mostly related to Yankee Atomic incremental dismantling costs and Vermont Yankee replacement energy costs related to a 2004 unscheduled outage.
• Nuclear decommissioning costs are related to our share of Maine Yankee, Connecticut Yankee and Yankee Atomic decommissioning costs. Our share of decommissioning costs increased $0.2 million, due to changes in FERC-approved rates in 2004.

Page 36 of 48

Operating Expenses Operating expenses represent costs incurred to support our core business. The table below provides the variances in income statement line items for Operating Expenses on the Condensed Consolidated Statements of Income for the first quarter of 2005 versus the same period in 2004, including the impact of the Rate Order (in thousands).