SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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FORM 10-Q
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X    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2003

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 by Rule 12b-2 of the Exchange Act). Yes       No   X   

At July 31, 2003, the latest practicable date for determination, 177,932 shares of common stock, without par value, of the registrant were outstanding.

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The accompanying notes are an integral part of the Consolidated Financial Statements.

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The accompanying notes are an integral part of the Consolidated Financial Statements.

* The Consolidated Balance Sheet at December 31, 2002 has been derived from the audited Consolidated Financial Statements at that date.

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The accompanying notes are an integral part of the Consolidated Financial Statements.

* The Consolidated Balance Sheet at December 31, 2002 has been derived from the audited Consolidated Financial Statements at that date.

**Debt securities issued by Virginia Electric and Power Company constitute 100 percent of the trust's assets.

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The accompanying notes are an integral part of the Consolidated Financial Statements.

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Note 1. Nature of Operations

Virginia Electric and Power Company (Virginia Power or the Company), a Virginia public service company, is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion). The Company is a regulated public utility that generates, transmits and distributes electric energy within a 30,000 square-mile area in Virginia and northeastern North Carolina. It sells electricity to approximately 2.2 million retail customers, including governmental agencies, and to wholesale customers such as rural electric cooperatives, municipalities, power marketers and other utilities. The Virginia service area comprises about 65 percent of Virginia's total land area but accounts for over 80 percent of its population. The Company has trading relationships beyond the geographic limits of its retail service territory and buys and sells wholesale electricity, natural gas and other energy commodities. Within this document, the term "Company" refers to the entirety of Virginia Electric and Power Company, including its Virginia and North Carolina operations, and all of its subsidiaries.

The Company manages its daily operations through two operating segments, Energy and Delivery. In addition, the Company also presents its corporate and other operations as a segment. See Note 14.

Note 2. Significant Accounting Policies

As permitted by the rules and regulations of the Securities and Exchange Commission (SEC), the accompanying unaudited Consolidated Financial Statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles). These unaudited Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes for the year ended December 31, 2002. On May 9, 2003, the Company filed a current report on Form 8-K that included its Consolidated Financial Statements and Notes for the year ended December 31, 2002, which were reformatted to reflect the transfer of electric transmission operations to the Energy segment from the Delivery segment effective January 1, 2003. References to the Consolidated Financial Statements and Notes for the year ended December 31, 2002 refer to those included in the May 9, 2003 current report on Form 8-K.

In the opinion of the Company's management, the accompanying unaudited Consolidated Financial Statements contain all adjustments, including normal recurring accruals, necessary to present fairly the Company's financial position as of June 30, 2003 and its results of operations for the three and six months and cash flows for the six months ended June 30, 2003 and 2002.

The accompanying unaudited Consolidated Financial Statements represent the accounts of the Company and its subsidiaries, with all significant intercompany transactions and accounts eliminated in consolidation.

The accompanying unaudited Consolidated Financial Statements reflect certain estimates and assumptions made by management in accordance with generally accepted accounting principles. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses for the periods presented. Actual results may differ from those estimates.

The Company reports certain contracts and instruments at fair value in accordance with generally accepted accounting principles. Market pricing and indicative price information from external sources are used to measure fair value when available. In the absence of this information, the Company estimates fair value based on near-term and historical price information and statistical methods. For individual contracts, the use of differing assumptions could have a material effect on the contract's estimated fair value. See Note 2 to the Consolidated Financial Statements for the year ended December 31, 2002 for more discussion of the Company's estimation techniques.

The results of operations for the interim periods are not necessarily indicative of the results expected for the full year. Information for quarterly periods is affected by seasonal variations in sales and other factors.

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Certain amounts in the 2002 Consolidated Financial Statements have been reclassified to conform to the 2003 presentation.

Depreciation

In the second quarter of 2002, the Company extended the estimated useful lives of most of its fossil fuel stations and electric transmission and distribution property based on depreciation studies that indicated longer lives were appropriate. These changes in estimated useful lives reduced depreciation expense by approximately $8 million and $24 million for the three and six months ended June 30, 2003, respectively.

In 2001, the Company extended the estimated useful lives of its nuclear facilities by 20 years. The impact of the change is fully reflected in depreciation expense for 2003 and 2002. The Company filed applications with the Nuclear Regulatory Commission (NRC) for 20-year life-extensions for its nuclear facilities in 2001 and received a renewed license for these units in March 2003.

Note 3. Accounting Changes

Effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, which provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. The Company has identified certain asset retirement obligations that are subject to the standard. These obligations are primarily associated with the decommissioning of its nuclear generation facilities.

Under SFAS No. 143, asset retirement obligations will be recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Under the present value approach used to estimate the fair value of asset retirement obligations, accretion of the liabilities due to the passage of time will be recognized as an operating expense. In addition, the reporting of realized and unrealized earnings of external trusts available for funding decommissioning activities at the Company's nuclear plants will be recorded in other income and other comprehensive income, as appropriate. Through 2002, the Company recorded these trusts' earnings in other income with an offsetting charge to expense, also recorded in other income, for the accretion of the decommissioning liability.

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The EITF 98-10 rescission was effective for non-derivative energy-related contracts initiated after October 25, 2002. For those non-derivative energy-related contracts initiated prior to October 25, 2002 in connection with the Company's energy trading activities, the Company reported the cumulative effect of this change in accounting principle as of January 1, 2003, resulting in an after-tax loss of $55 million.

The rescission of EITF 98-10, along with other provisions of EITF 02-3, also affects the classification of realized and unrealized gains and losses arising from derivative energy contracts no longer considered to be held for trading purposes, on the Consolidated Statements of Income. As permitted by EITF 98-10, for periods prior to January 1, 2003, the Company presented all changes in fair value of derivative and non-derivative energy-related contracts that are held in connection with the Company's energy trading activities, including amounts realized upon settlement, in revenue on a net basis. Under the provisions of EITF 02-3, for those energy-related derivative instruments determined to be held for trading purposes, all changes in fair value, including amounts realized upon settlement, continue to be presented in revenue on a net basis. A derivative contract is held for trading purposes if the intent of the transaction is to generate profits on short-term differences in price. For non-trading derivatives not designated as hedges, all unrealized changes in fair value are presented in other operations and maintenance expense on a net basis. For non-trading derivative contracts that involve physical delivery of commodities, gross sales contract settlements are presented in revenue, while gross purchase contract settlements are reported in expenses.

As described more fully in Note 4 to the Consolidated Financial Statements for the year ended December 31, 2002, in January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46, Consolidation of Variable Interest Entities (FIN 46). FIN 46 addresses consolidation by business enterprises of entities that are not controllable through voting interests or in which the equity investors do not bear the residual economic risks and rewards. The initial adoption of the provisions of FIN 46 on July 1, 2003 by the Company will not impact its results of operations. A description of the Company's involvement with variable interest entities follows:

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As previously discussed in Note 21 to the Consolidated Financial Statements for the year ended December 31, 2002, the Company entered into agreements with another Dominion subsidiary (lessor) in order to finance and lease a new power generation facility. Under existing accounting guidance, neither the project assets nor related debt would be reported on the Company's Consolidated Balance Sheets upon inception of the lease. The project was completed on July 1, 2003, at which time the facility was put into service and the lease agreement became effective. Under FIN 46, the lessor is considered a variable interest entity and the Company has been determined to be the primary beneficiary and will therefore consolidate it in the preparation of its Consolidated Financial Statements. Based upon total project costs expected to be incurred for the project, consolidation of this variable interest entity, beginning July 1, 2003, will result in an additional $370 million in property, plant and equipment and related debt.

Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts

As described more fully in Note 16 to the Consolidated Financial Statements for the year ended December 31, 2002, the Company established Virginia Power Capital Trust II (trust) which sold trust preferred securities to third party investors. The Company received the proceeds from the sale of the trust preferred securities in exchange for junior subordinated notes issued by the Company to be held by the trust. Under existing accounting guidance, the Company consolidates the trust in the preparation of its Consolidated Financial Statements because it has a majority voting interest in the trust. Under FIN 46, the trust is considered a variable interest entity. Based on the trust structure as of July 1, 2003, the Company is not considered the primary beneficiary of the trust and thus will cease consolidating the trust beginning on July 1, 2003. Under these circumstances, the Company's Consolidated Balance Sheets will no longer reflect the trust preferred securities, but instead will report the junior subordinate d instruments held by the trust as long-term debt. The Company is currently evaluating changes to the trust structure that, if implemented, could possibly result in a determination that the Company is the primary beneficiary of the trust, thus requiring the Company to resume the consolidation of the trust in the preparation of its Consolidated Financial Statements. If the trust were to be consolidated subsequent to July 1, 2003, the trust preferred securities would be presented as liabilities as described under the Liabilities and Equity Classification section below.

In May 2003, FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. The standard requires an issuer to classify and measure certain freestanding financial instruments with characteristics of both liabilities and equity as a liability if that financial instrument embodies an obligation requiring the issuer to redeem the financial instruments by transferring its assets. Under this standard, obligated mandatorily redeemable preferred securities would be reported as liabilities. However, as described under the Consolidation of Variable Interest Entities section above, consolidation of the underlying trust must be evaluated under FIN 46 before application of this Statement.

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On April 30, 2003, FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. The amendment reflects decisions made by FASB and the Derivatives Implementation Group (DIG) process in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS No. 149 will be applied prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. SFAS No. 149 provisions that resulted from the DIG process that became effective in quarters beginning before June 15, 2003 will continue to be applied based upon their original effective dates. The Company is presently evaluating the potential impact of SFAS No. 149 on its results of operations and financial position.

In connection with the January 2003 EITF meeting, FASB was requested to reconsider an interpretation of SFAS No. 133. The interpretation, which is contained in the DIG's C11 guidance, relates to contracts with pricing terms that include broad market indices. In particular, that guidance discusses whether a contract's pricing terms that contain broad market indices (e.g., consumer price index) could qualify as a normal purchase or sale and therefore not be subject to fair value accounting. The Company has certain power purchase and sale contracts subject to this guidance. On June 25, 2003, the FASB issued Statement 133 Implementation Issue No. C20, Interpretation of the Meaning of 'Not Clearly and Closely Related' in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature, to clarify the guidance applicable to these circumstances. Under C20, criteria are established to determine if the price adjustment is not clearly and closely related to the underlying asset being purchased or sold under the contract, including whether the price adjustment is extraneous or disproportionate to the fair value of the underlying asset or direct component thereof. Under C20, the assessment should include both qualitative and quantitative considerations and should be performed only at inception of the contract. The provisions of C20 should be applied prospectively for all new and existing contracts beginning the first fiscal quarter after July 10, 2003. The Company has several power contracts that are subject to this guidance but has not completed its assessment of whether those contracts meet the provisions of C20. Assuming such contracts qualify as normal purchase or sale contracts under the new guidance, the Company will record these power contracts at estimated fair value, determined at the time of implementing C20, and will report the change as the cumulative effect of a change in accounting principle.

EITF 01-8

In May 2003, the EITF reached a consensus on Issue No. 01-8, Determining Whether an Arrangement Contains a Lease (EITF 01-8). Under the provisions of EITF 01-8, arrangements conveying the right to control the use of specific property, plant or equipment must be evaluated to determine whether they contain a lease. The Company enters into contracts for the long-term purchase and sale of electric generation capacity and energy that, depending on the facts and circumstances, could be subject to EITF 01-8. The new rules will be applied prospectively to contracts entered into or modified after July 1, 2003.

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Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services subject to cost-of-service rate regulation.

Non-regulated electric sales consist primarily of sales of electricity at market-based rates and net revenue from electric trading activities.

Non-regulated gas sales consist primarily of sales of natural gas at market-based rates, brokered gas and net revenue from gas trading activities.

Other revenue consists primarily of miscellaneous service revenue from rate-regulated electric distribution, sales of coal and brokered oil and other miscellaneous revenue.

The composition of revenue from non-regulated electric sales, non-regulated gas sales and other revenue has changed since being described in Note 5 to the Consolidated Financial Statements for the year ended December 31, 2002. The changes were effective January 1, 2003 and related to the impact of adopting EITF 02-3 on the reporting of revenue and expenses for energy trading activities, as described in Note 3 and as follows:

For derivative contracts previously presented in revenue on a net basis: For non-trading derivatives not designated as hedges, all unrealized changes in fair value are presented in other operations and maintenance expense on a net basis. For non-trading derivative contracts that involve physical delivery of commodities, gross sales contract settlements are presented in revenue for non-regulated electric sales, non-regulated gas sales and other revenue, as applicable, while gross purchase contract settlements are reported in expenses.

For non-derivative contracts previously presented in revenue on a net basis: Non-derivative energy-related contracts, previously subject to fair value accounting under EITF 98-10, are now subject to accrual accounting. Revenue for non-regulated electric sales, non-regulated gas sales and other revenue now include settlements of sales contracts at the time of contract performance, settlement or termination, on an accrual basis. These contracts will no longer be reported at fair value in the Company's Consolidated Financial Statements.

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Note 6.     Liability for 2001 Severance Costs

The Company recognized costs and the related liability associated with employee severances in 2001. The change in this liability during the six months ended June 30, 2003 is presented below:

For additional information, see Note 6 to the Consolidated Financial Statements for the year ended December 31, 2002.

The following table presents total comprehensive income:

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Note 8. Derivatives and Hedge Accounting

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The following table presents selected information related to cash flow hedges included in Accumulated Other Comprehensive Income (AOCI) in the Consolidated Balance Sheet at June 30, 2003:

The actual amounts that will be reclassified to earnings during the next 12 months will vary from the expected amounts presented above as a result of changes in interest rates and foreign exchange rates. The effect of amounts being reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated purchases) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies.

Dominion, Consolidated Natural Gas (CNG) and the Company are parties to two joint credit facilities that allow aggregate borrowings of up to $2 billion. In May 2003, Dominion, CNG and the Company entered into a joint credit facility that allows aggregate borrowings of up to $1.25 billion. This credit facility replaced the $1.25 billion 364-day credit facility that matured during the second quarter of 2003. In May 2002, Dominion, CNG and the Company entered into a $750 million 3-year revolving credit facility that terminates in May 2005. The credit facilities will be used for working capital; as support for the combined commercial paper programs of Dominion, CNG and the Company; and other general corporate purposes.

The 3-year facility can also be used to support up to $200 million of letters of credit. At June 30, 2003, total outstanding letters of credit supported by the 3-year facility were $199 million, which were issued on behalf of CNG and other Dominion subsidiaries.

In February 2003, the Company issued $400 million aggregate principal amount of its 2003 Series A 4.75 percent senior notes due March 1, 2013 and repaid $10 million of maturing medium-term notes.

In April 2003, the Company repaid $200 million of 1993 Series B, 6.625 percent mortgage bonds.

See Note 4 for a discussion of the impact of FIN 46 on reported debt amounts, effective July 1, 2003, related to assets leased from another Dominion subsidiary and preferred securities issued by a subsidiary trust.

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The following table describes the changes to the Company's asset retirement obligations during the six months ended June 30, 2003:

The Company has established external trusts dedicated to funding the future decommissioning of its nuclear plants. At June 30, 2003, the aggregate fair value of these trusts, consisting primarily of debt and equity securities, totaled $928 million.

Had the provisions of SFAS No. 143 been applied for the following periods in 2003 and 2002, the Company's net income would have been as follows:

Had the provisions of SFAS No. 143 been applied for the following periods, the asset retirement obligations would have been as follows:

As permitted by SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, the Company accrues for future costs of removal for its cost-of-service rate regulated transmission and distribution assets, even if no legal obligation to perform such activities exists. At June 30, 2003 and December 31, 2002, the Company's accumulated depreciation and amortization included $390 million and $375 million, respectively, representing the estimated future cost of such removal activities.

See Note 3 for further discussion of the adoption of SFAS No. 143.

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Note 11. Commitments and Contingencies

Other than the matters discussed below, there have been no significant developments regarding commitments and contingencies disclosed in Note 21 to the Consolidated Financial Statements for the year ended December 31, 2002, nor have any significant new matters arisen during the six months ended June 30, 2003.

As previously reported in Note 21 to the Consolidated Financial Statements for the year ended December 31, 2002, the Company received a Notice of Violation in 2000 from the United States Environmental Protection Agency related to some specified construction projects at the Mt. Storm Power Station in West Virginia. Thereafter, New York State filed a suit against the Company alleging similar violations, and the suit was stayed. The Company reached an agreement in principle with the federal government and the state of New York to resolve the matter, and the states of Virginia, West Virginia, Connecticut and New Jersey joined the United States and the state of New York in seeking to reach a final agreement with the Company. A settlement agreement in the form of a proposed Consent Decree was agreed to on April 21, 2003, by the U.S. Department of Justice and the U.S. Environmental Protection Agency for the United States of America, by the states of Virginia, West Virginia, Connecticut, New Jersey and New York and by the Company. In accordance with the settlement, the United States filed an action in the Eastern District of Virginia against the Company and the Consent Decree was lodged with that court to settle that action. Virginia and West Virginia also filed complaints in intervention in the Virginia federal district court. The New York State federal district court action has been transferred to the Virginia federal district court, and it is anticipated that, in addition to New York, Connecticut and New Jersey will join as plaintiffs in that proceeding. The EPA public comment period has now closed. It is anticipated that in the near future the Virginia federal district court will be asked to enter the Consent Decree finalizing the settlement and resolving the underlying actions, but retaining jurisdiction pursuant to the terms of the Consent Decree. The settlement is consistent with the previously reported agreement in principle and includes payment of a $5 million civil penalty, an obligation to fund $14 million f or environmental projects and a commitment to improve air quality under the Consent Decree estimated to involve expenditures of $1.2 billion. The Company has already incurred certain capital expenditures for environmental improvements at its coal-fired stations in Virginia and West Virginia and has committed to additional measures in its current financial plans and capital budget to satisfy the requirements of the Consent Decree. As of June 30, 2003, the Company had accrued $19 million for the civil penalty and the funding of the environmental projects, substantially all of which was recorded in 2000.

At June 30, 2003, the Company had issued $67 million of surety bonds, of which $57 million is associated with the financial assurance requirements imposed by the NRC with respect to the decommissioning of the Company's nuclear units. Under the terms of the surety bonds, the Company is obligated to indemnify the respective surety bond company for any amounts paid.

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Note 12. Related Party Transactions

The Company, through an unregulated subsidiary, exchanges certain quantities of natural gas with affiliates at market prices in the ordinary course of business. The affiliated commodity transactions are presented below:

Through the same unregulated subsidiary, the Company is involved in facilitating Dominion's enterprise risk management strategy. In connection with this strategy, the Company enters into certain commodity derivative contracts with other Dominion affiliates. These contracts, which are principally comprised of commodity swaps, are used by Dominion affiliates to manage commodity price risks associated with purchases and sales of natural gas. As part of Dominion's enterprise risk management strategy, the Company generally manages such risk exposures by entering into offsetting derivative instruments with non-affiliates. The Company reports both affiliated and non-affiliated derivative instruments at fair value, with related changes included in earnings. At June 30, 2003 and December 31, 2002, the Company's Consolidated Balance Sheets included derivative assets with Dominion affiliates of $120 million and $84 million and derivative liabilities with Dominion affiliates of $87 million and $90 mil lion, respectively. The Company's income from operations includes the recognition of the following derivative gains and losses on affiliated transactions:

Dominion Resources Services, Inc. (Dominion Services) provides certain administrative and technical services to the Company. The cost of services provided by Dominion Services to the Company in the second quarter of 2003 and 2002 was approximately $75 million and $67 million, respectively, and in the first six months of 2003 and 2002 was approximately $147 million and $131 million, respectively. The Company provides certain services to affiliates, including charges for facilities and equipment usage. The cost of services provided by the Company to Dominion Services and other Dominion affiliates was approximately $8 million and $10 million for the three months ended June 30, 2003 and 2002, respectively, and, for the six months ended June 30, 2003 and 2002, was approximately $14 million and $15 million, respectively.

The Company and its subsidiaries have made certain borrowings from Dominion pursuant to a short-term demand note. At June 30, 2003 and December 31, 2002, net outstanding borrowings under this note totaled $215 million and $100 million, respectively. Interest charges related to this note in the second quarter and the first six months of 2003 were not material.

The Company's accounts receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions.

For information about the Company's agreement with Dominion Equipment II, Inc. to develop, construct, finance and lease a new power generation facility at the Company's Possum Point station in Prince William County, Virginia, see Note 21 to the Consolidated Financial Statements for the year ended December 31, 2002. Also, see Note 4 for a discussion of the impact of FIN 46 on this lease arrangement.

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An unregulated subsidiary of the Company, at its sole discretion, has provided at June 30, 2003 and December 31, 2002, approximately $17 million and $31 million, respectively, of cash collateral to third parties on behalf of several of its natural gas supply customers. For this and other financial support services, the unregulated subsidiary receives fees and has a security interest in the customers' assets. The arrangements terminate at various dates beginning in 2005 through 2007, subject to periodic renewal thereafter unless terminated by either party.

For additional information on transactions with related parties, see Note 24 to the Consolidated Financial Statements for the year ended December 31, 2002.

The Company calculates its gross credit exposure for each counterparty as the unrealized fair value of derivative and energy trading contracts plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral. However, to the extent a counterparty has fully prepaid transactions by transferring cash or posting letters of credit, the Company has excluded such amounts from its gross credit exposure. In the calculation of net credit exposure, the Company's gross exposure is reduced by collateral made available by counterparties, including letters of credit and cash received by the Company and held as margin deposits, made available by counterparties as a result of exceeding agreed-upon credit limits. Presented below is a summary of the Company's gross and net credit exposure as of June 30, 2003. The amounts presented exclude accounts receivable for regulated electric retail distribution and regulated electric transmission services, amounts receivable from affiliated companies and the Company's provision for credit losses. See Note 23 to the Consolidated Financial Statements for the year ended December 31, 2002 for a discussion of the nature of the Company's credit risk exposures.

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The Company manages its operations through the following segments:

Energy manages the Company's portfolio of generating facilities and power purchase contracts. It also manages the Company's energy trading, marketing, hedging and arbitrage activities. Energy also manages the electric transmission operations formerly managed by Delivery. Amounts for 2002 have been restated to reflect the management of electric transmission by Energy effective January 1, 2003.

Delivery manages the Company's electric distribution as well as metering services and customer service. The segment continues to be subject to the requirements of SFAS No. 71. Amounts for 2002 have been restated to reflect the management of electric transmission by Energy effective January 1, 2003.

Corporate and Other includes certain expenses which are not allocated to the Energy and Delivery segments, including those related to the following: 1) corporate operations and assets; 2) severance costs related to 2003 workforce reduction; and 3) the 2003 cumulative effect of changes in accounting principle (see Note 3).

See Note 26 to the Consolidated Financial Statements for the year ended December 31, 2002 for more information about the Company's segments.