10-K

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2004

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 1-2255

VIRGINIA ELECTRIC AND POWER COMPANY

(Exact name of registrant as specified in its charter)

Virginia	54-0418825
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
701 East Cary Street Richmond, Virginia	23219
(Address of principal executive offices)	(Zip Code)

(804) 819-2000

(Registrant’s telephone number)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Preferred Stock (cumulative), $100 par value, $5.00 dividend	New York Stock Exchange
7.375% Trust Preferred Securities (cumulative), $25 par value	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

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

The aggregate market value of the voting stock held by non-affiliates as of the last business day of the registrant’s most recently completed second fiscal quarter was zero.

As of February 1, 2005, there were issued and outstanding 198,047 shares of the registrant’s common stock, without par value, all of which were held, beneficially and of record, by Dominion Resources, Inc.

DOCUMENTS INCORPORATED BY REFERENCE.

None

Virginia Electric and Power Company

Item Number		Page Number
Part I
1.	Business	1
2.	Properties	6
3.	Legal Proceedings	7
4.	Submission of Matters to a Vote of Security Holders	7
Part II
5.	Market for the Registrant’s Common Equity and Related Stockholder Matters	8
6.	Selected Financial Data	8
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	8
7A.	Quantitative and Qualitative Disclosures About Market Risk	26
8.	Financial Statements and Supplementary Data	28
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	55
9A.	Controls and Procedures	55
9B.	Other Information	55
Part III
10.	Directors and Executive Officers of the Registrant	56
11.	Executive Compensation	58
12.	Security Ownership of Certain Beneficial Owners and Management	62
13.	Certain Relationships and Related Transactions	62
14.	Principal Accountant Fees and Services	62
Part IV
15.	Exhibits and Financial Statement Schedules	63

Part 1

Item 1. Business

The Company

Virginia Electric and Power Company (the Company) is a regulated public utility that generates, transmits and distributes power for sale in Virginia and northeastern North Carolina. In Virginia, the Company conducts business under the name “Dominion Virginia Power.” In North Carolina, the Company conducts business under the name “Dominion North Carolina Power” and serves retail customers located in the northeastern region of the state, excluding certain municipalities. In addition, the Company sells electricity at wholesale to rural electric cooperatives, power marketers, municipalities and other utilities. Within this document, “the Company” refers to the entirety of Virginia Electric and Power Company, including its Virginia and North Carolina operations and all of its subsidiaries.

All of the Company’s common stock is owned by its parent company, Dominion Resources, Inc. (Dominion), a fully integrated gas and electric holding company.

As of December 31, 2004, the Company had approximately 7,100 full-time employees. Approximately 3,300 employees are subject to collective bargaining agreements.

The Company was incorporated in 1909 as a Virginia public service corporation. Its principal executive offices are located at 701 East Cary Street, Richmond, Virginia 23219 and its telephone number is (804) 819-2000.

Operating Segments

The Company manages its operations through three primary operating segments: Delivery, Energy and Generation. The Company also reports Corporate and Other functions as a segment. While the Company manages its daily operations as described below, its assets remain wholly-owned by it and its legal subsidiaries. For additional financial information on business segments and geographic areas, see Notes 1 and 23 to the Consolidated Financial Statements.

Delivery

Delivery includes the Company’s electric distribution system and customer service operations. Electric distribution operations serve residential, commercial, industrial and governmental customers in Virginia and northeastern North Carolina.

Competition

Within Delivery’s certificated service territory in Virginia and North Carolina, there is no competition for electric distribution service.

Regulation

Delivery’s electric retail service, including the rates it may charge to customers, is subject to regulation by the Virginia State Corporation Commission (Virginia Commission) and the North Carolina Utilities Commission (North Carolina Commission). See Regulation – State Regulations for additional information.

Properties

The Delivery segment electric distribution network includes approximately 54,000 miles of distribution lines, exclusive of service level lines in Virginia and North Carolina. The right-of-way grants for most of the Company’s electric lines have been obtained from the apparent owner of real estate, but underlying titles have not been examined except for transmission lines of 69kV or more . Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked.

Sources of Fuel Supply

Delivery’s supply of electricity to serve its retail customers is primarily provided by the Generation segment. See Generation for additional information.

Seasonality

Delivery’s business typically varies seasonally based on demand for electricity by residential and commercial customers for cooling and heating use due to changes in temperature.

Energy

Energy includes a regulated electric transmission system located in Virginia and northeastern North Carolina and the Company’s Clearinghouse operations, which is responsible for energy trading (exclusive of marketing excess utility generation), marketing and risk management activities.

During the fourth quarter of 2004, the Company performed an evaluation of its Clearinghouse trading and marketing operations, which resulted in a decision to exit certain energy trading activities and instead focus on the optimization of company assets. Beginning in 2005, all revenue and expenses from the Clearinghouse’s optimization of Company assets will be reported as part of the results of the business segments operating the related assets. As a result of these changes, 2004 and 2003 results now reflect revenue and expenses associated with coal trading and marketing activities in the Generation segment rather than the Energy segment.

Competition

Energy’s electric transmission business is not subject to competition for transmission service to loads served within its Virginia and North Carolina service territories. In connection with transmission service to loads outside of its electric service territory, the Company’s electric transmission business competes with other electric transmission providers, primarily on the basis of rates and availability of service.

Regulation

Energy’s electric transmission operations are subject to regulation by the Federal Energy Regulatory Commission (FERC), the Virginia Commission and the North Carolina Commission. See State Regulations and Federal Regulations in Regulation for additional information.

2004 / Page 1

Properties

The Energy segment has approximately 6,000 miles of electric transmission lines located in the states of North Carolina, Virginia and West Virginia. Portions of the electric transmission lines cross national parks and forests under permits entitling the federal government to use, at specified charges, surplus capacity in the line, if any exists.

The Company maintains major interconnections with Progress Energy, American Electric Power Company, Inc., PJM-West and PJM. Through this major transmission network, the Company has arrangements with these entities for coordinated planning, operation, emergency assistance and exchanges of capacity and energy. See Regional Transmission Organization (RTO) in Future Issues and Other Matters in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A).

Seasonality

The Energy segment is affected by seasonal changes in the prices of commodities that it markets and trades.

Generation

Generation includes the Company’s electric generation operations. The Company’s strategy for its electric generation operations focuses on serving customers in Virginia and northeastern North Carolina.

As a result of the reorganization of the Company’s Clearinghouse operations, Generation’s 2004 and 2003 results now reflect revenue and expenses associated with coal trading and marketing activities performed by the Clearinghouse that were previously reported in the Energy segment.

In February 2005, the Company paid $42 million in cash and assumed $62 million in debt in connection with the termination of a long-term power purchase agreement and acquisition of the related generating facility used by Panda-Rosemary, LP, a non-utility generator, to provide electricity to the Company. See Restructuring of Contract with Non-Utility Generator in Future Issues and Other Matters in MD&A for additional information.

Competition

For the Company’s electric generation operations, retail choice has been available for all of the Company’s Virginia electric customers since January 1, 2003; however, to date, competition in Virginia has not developed to the extent originally anticipated. See Regulation-State Regulations. Currently, North Carolina does not offer retail choice to electric customers.

Regulation

In Virginia and North Carolina, the Company’s electric utility generation facilities, along with power purchases, are used to serve its utility service area obligations. Due to 2004 deregulation legislation, revenues for serving Virginia jurisdictional retail load are based on capped rates through 2010 and the related fuel costs for the generating fleet, including power purchases, are subject to a fixed rate recovery through July 1, 2007 when a one-time prospective adjustment will be considered. During this transition period, the risk of fuel factor-related cost recovery shortfalls may adversely impact the Company’s cost structure. Conversely, the Company may experience a positive economic impact to the extent it can reduce its fuel factor-related costs. Subject to market conditions, any generation remaining after meeting utility system needs is sold outside the Company’s service area. See Regulation-State Regulations and Regulation-Federal Regulations-Environmental Regulations for additional information.

Properties

For a listing of the Company’s generation facilities, see Item 2. Properties.

Sources of Fuel Supply

Generation uses a variety of fuels to power its electric generation. These include a mix of both nuclear fuel and fossil fuel as described further below.

Nuclear Fuel – Generation utilizes primarily long-term contracts to support its nuclear fuel requirements. Worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices. Current agreements, inventories and spot market availability are expected to support current and planned fuel supply needs. Additional fuel is purchased as required to ensure optimum cost and inventory levels.

Fossil Fuel – Generation utilizes coal, oil and natural gas in its fossil fuel operations. Generation’s coal supply is obtained through long-term contracts and spot purchases. Oil-fired generation is used primarily to support heavier system generation loads during very cold or very hot weather periods. Additional utility requirements are purchased mainly under short-term spot agreements.

Firm natural gas transportation contracts (capacity) exist that allow delivery of gas to Generation’s facilities. Generation’s capacity portfolio allows flexible natural gas deliveries to its gas turbine fleet, while minimizing costs.

Seasonality

Sales of electricity for the Generation segment vary seasonally based on demand for electricity by residential and commercial customers for cooling and heating use due to seasonal changes in temperature.

Nuclear Decommissioning

Generation has four licensed, operating nuclear reactors at its Surry and North Anna plants in Virginia that serve customers of the Company’s regulated electric utility operations. Decommissioning represents the decontamination and removal of radioactive contaminants from a nuclear power plant once operations have ceased, in accordance with standards established by the Nuclear Regulatory Commission (NRC). Amounts collected from ratepayers and placed in trusts are being invested to fund the expected future costs of decommissioning the Surry and North Anna units.

The total estimated cost to decommission the Company’s four nuclear units is $1.5 billion based upon site-specific studies completed in 2002. The Company expects to perform new cost studies in 2006. The cost estimate assumes that the method of completing decommissioning activities is prompt dismantlement. During 2003, the NRC approved the Company’s application for a 20-year life extension for the Surry and North Anna units. The

2004 / Page 2

Company expects to decommission the units during the period 2032 to 2045.

	Surry				North Anna
	Unit 1		Unit 2		Unit 1		Unit 2		Total
(millions)
NRC license expiration year		2032		2033		2038		2040
Current cost estimate (2002 dollars)	$	375	$	368	$	391	$	363	$	1,497
Funds in trusts at December 31, 2004		313		308		256		242		1,119
2004 contributions to trusts		11		11		7		7		36

Corporate and Other

The Company also has a Corporate and Other segment. Corporate and Other represents the Company’s corporate and other functions and specific items attributable to the Company’s operating segments that are reported in Corporate and Other.

Regulation

The Company is subject to regulation by the Securities and Exchange Commission (SEC), FERC, the Environmental Protection Agency (EPA), Department of Energy (DOE), the NRC, the Army Corps of Engineers, and other federal, state and local authorities.

State Regulations

The Company is subject to regulation by the Virginia Commission and the North Carolina Commission.

The Company holds certificates of public convenience and necessity authorizing it to maintain and operate its electric facilities now in operation and to sell electricity to customers. However, it may not construct or incur financial commitments for construction of any substantial generating facilities or large capacity transmission lines without the prior approval of various state and federal government agencies.

Status of Electric Deregulation in Virginia

The Virginia Electric Utility Restructuring Act (Virginia Restructuring Act) was enacted in 1999 and established a plan to restructure the electric utility industry in Virginia. The Virginia Restructuring Act addressed, among other things: capped base rates, RTO participation, retail choice, the recovery of stranded costs and the functional separation of a utility’s electric generation from its electric transmission and distribution operations.

Retail choice has been available to all of the Company’s Virginia regulated electric customers since January 1, 2003. The Company has also separated its generation, distribution and transmission functions through the creation of divisions. Codes of conduct ensure that Virginia Power’s generation and other divisions operate independently and prevent cross-subsidies between the generation and other divisions.

Since the passage of the Virginia Restructuring Act, the competitive environment has not developed in Virginia as anticipated. In April 2004, the Governor of Virginia signed into law amendments to the Virginia Restructuring Act and the Virginia fuel factor statute. The amendments extend capped base rates to December 31, 2010, unless modified or terminated earlier under the Virginia Restructuring Act. In addition to extending capped rates, the amendments:

• Lock in the Company’s fuel factor provisions until the earlier of July 1, 2007 or the termination of capped rates;

• Provide for a one-time adjustment of the Company’s fuel factor, effective July 1, 2007 through December 31, 2010 (unless capped rates are terminated earlier under the Virginia Restructuring Act), with no adjustment for previously incurred over-recovery or under-recovery, thus eliminating deferred fuel accounting for the Virginia jurisdiction; and

• End wires charges on the earlier of July 1, 2007 or the termination of capped rates, consistent with the Virginia Restructuring Act’s original timetable.

The risk of fuel factor-related cost recovery shortfalls may adversely impact the Company’s cost structure during the transition period and it could realize the negative economic impact of any such adverse event. Conversely, the Company may experience a positive economic impact to the extent that it can reduce its fuel factor-related costs for its electric utility generation-related operations.

Other amendments to the Virginia Restructuring Act were also enacted with respect to a minimum stay exemption program, a wires charge exemption program and allowing the development of a coal-fired generating plant in southwest Virginia for serving default service needs. Under the minimum stay exemption program, large customers with a load of 500 kW or greater would be exempt from the twelve-month minimum stay obligation under capped rates if they return to supply service from the incumbent utility at market-based pricing after they have switched to supply service with a competitive service provider.

The wires charge exemption program would allow large industrial and commercial customers, as well as aggregated customers in all rate classes, to avoid paying wires charges when selecting supply service from a competitive service provider by agreeing to market-based pricing upon return to the incumbent electric utility. Customers electing this option would waive the right to return to capped rate service from the incumbent electric utility. The program is limited to the first 1,000 Mw of load or eight percent of the utility’s prior year Virginia adjusted peak load in the first 18 months of the program.

In January 2005, the Company filed compliance plans and the required market-based pricing methodology for both programs with the Virginia Commission. To encourage a successful program and the development of retail competition, the Company has proposed that customers that enroll with a competitive service provider in the wires charge exemption program in 2005 be allowed to return to service with the Company at capped rates after October 2007 instead of market-based pricing. The Virginia Commission must approve these proposals prior to implementation.

In December 2004, the Company filed its annual market prices/wires charges compliance plan with the Virginia Commission. Calculation of the 2005 wires charges in accordance with the formula approved by the Virginia Commission produced zero wires charges for 2005 for all but a few smaller rate classes. As a result,

2004 / Page 3

the Company voluntarily agreed to forego the collection of any wires charges during 2005. The Company’s decision to forego wires charges in 2005 is not intended to set a precedent for subsequent periods. The Company intends to collect wires charges in future periods should the Virginia Commission-approved methodology determine that wires charges are applicable.

See Status of Deregulation in Virginia in Future Issues and Other Matters in MD&A for additional information on capped base rates, stranded costs and RTO participation.

Retail Access Pilot Programs

The three retail access pilot programs, approved by the Virginia Commission in 2003, continue to be available to customers. These programs are to run through the remainder of the capped rate period and will make available to competitive service providers up to 500 megawatts of load, with potential participation of more than 65,000 customers from a variety of customer classes.

Rate Matters

Virginia—In December 2003, the Virginia Commission approved the Company’s proposed settlement of its 2004 fuel factor increase of $386 million. The settlement includes a recovery period for the under-recovery balance over three and a half years. Approximately $171 million of the $386 million was recovered in 2004 with $85 million to be recovered in 2005, $87 million in 2006 and $43 million in the first six months of 2007.

As a result of amendments to the Virginia Restructuring Act in 2004, the Company’s capped based rates were extended to December 31, 2010. In addition, the Company’s fuel factor provisions were frozen until July 1, 2007, after which they can be only adjusted once more through December 31, 2010. See Status of Electric Deregulation in Virginia above for additional information regarding the Virginia Restructuring Act amendments.

North Carolina—In connection with the North Carolina Commission’s approval of Dominion’s acquisition of Consolidated Natural Gas Company (CNG), the Company agreed not to request an increase in North Carolina retail electric base rates before 2006, except for certain events that would have a significant financial impact on the Company’s electric utility operations. Fuel rates are still subject to change under the annual fuel cost adjustment proceedings. However in April 2004, the North Carolina Commission commenced an investigation into the Company’s North Carolina base rates and subsequently ordered the Company to file a general rate case to show cause why its North Carolina base rates should not be reduced. The rate case was filed in September 2004 and in February 2005, the Company reached a tentative settlement with parties in the case that is subject to North Carolina Commission approval before becoming effective.

Federal Regulations

Public Utility Holding Company Act of 1935 (1935 Act)

Dominion is a registered holding company under the 1935 Act. The 1935 Act and related regulations issued by the SEC govern activities of Dominion and its subsidiaries, including the Company, with respect to the issuance and acquisition of securities, acquisition and sale of utility assets, certain transactions among affiliates, engaging in business activities not directly related to the utility or energy business and other matters. The Company’s activities in these areas may also be regulated at the state level by the Virginia Commission and the North Carolina Commission. In some cases, the SEC’s rules under the 1935 Act provide that the obtaining of state approvals will also suffice for 1935 Act purposes, subject to the fulfillment of certain post-transaction reporting requirements.

Federal Energy Regulatory Commission

Under the Federal Power Act, FERC regulates wholesale sales of electricity and transmission of electricity in interstate commerce by public utilities. The Company sells electricity in the wholesale market under its market-based sales tariff authorized by FERC but does not make wholesale power sales under this tariff to loads located within its service territory. In addition, the Company has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside its service territory. Any such sales would be voluntary. The Company’s sales of natural gas, liquid hydrocarbon by-products and oil in wholesale markets are not regulated by FERC.

The Virginia Restructuring Act requires that the Company join an RTO, and FERC encourages RTO formation as a means to foster wholesale market formation. The Company and PJM Interconnection, LLC (PJM) entered into an agreement in September 2002 that provides for, subject to regulatory approval and certain provisions, the Company to become a member of PJM and transfer functional control of its electric transmission facilities to PJM for inclusion in a new PJM South Region. In October 2004, FERC issued an order conditionally approving the Company’s application to join PJM, and in November 2004, the Virginia Commission approved the Company’s application to join PJM subject to certain terms and conditions. The North Carolina Commission evidentiary hearing was held in January 2005. The Company cannot predict the outcome of this matter at this time.

In a separate order issued in September 2004, FERC granted authority to the Company and its affiliates with market based rate authority to charge market based rates for sales of electric energy and capacity to loads located within the Company’s service territory upon its integration into PJM. For additional information, see RTO in Future Issues and Other Matters in MD&A.

The Company is also subject to FERC’s Standards of Conduct that govern conduct between interstate transmission gas and electricity providers and their marketing function or their energy related affiliates. The rule defines the scope of the affiliates

2004 / Page 4

covered by the standards and is designed to prevent transmission providers from giving their marketing functions or affiliates undue preferences.

In June 2004, FERC approved the Company’s filing to provide optional backup supply service to competitive service providers serving retail customers, including the retail pilot programs, in the Company’s service territory in Virginia. The filing addressed competitive service providers’ concerns with the availability of transmission capacity to move energy into Virginia. The backup supply service will allow competitive service providers to continue to serve their customers in the Company’s service area in Virginia during periods of supply interruption. This is an interim solution until the Company is integrated into PJM.

Environmental Regulations

Each operating segment faces substantial regulation and compliance costs with respect to environmental matters. For discussion of significant aspects of these matters, including current and planned capital expenditures relating to environmental compliance, see Environmental Matters in Future Issues and Other Matters in MD&A. Additional information can also be found in Item 3. Legal Proceedings and Note 19 to the Consolidated Financial Statements.

From time to time, the Company may be identified as a potentially responsible party to a Superfund site. The EPA (or a state) can either (a) allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or (b) conduct the remedial investigation and action and then seek reimbursement from the parties. Each party can be held jointly, severally and strictly liable for all costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, the Company may be responsible for the costs of remedial investigation and actions under the Superfund Act or other laws or regulations regarding the remediation of waste. The Company does not believe that any currently identified sites will result in significant liabilities.

In January 2004, the EPA proposed additional regulations addressing pollution transport from electric generating plants as well as the regulation of mercury and nickel emissions. These regulatory actions, in addition to revised regulations to address regional haze, are expected to be finalized in 2005 and could require additional reductions in emissions from the Company’s fossil fuel-fired generating facilities. If these new emission reduction requirements are imposed, additional significant expenditures may be required.

In March 2004, the State of North Carolina filed a petition under Section 126 of the Clean Air Act seeking the EPA to impose additional nitrogen oxide (NO_x) and sulfur dioxide (SO₂) reductions from electrical generating units in thirteen states, claiming emissions from the electrical generating units in those states are contributing to air quality problems in North Carolina. The Company has electrical generating units in two of the states. The issues raised by North Carolina are already being addressed by the EPA in current regulatory initiatives. The EPA is expected to respond to the petition in 2005. Given the highly uncertain outcome and timing of future action, if any, by the EPA on this issue, the Company cannot predict the financial impact, if any, on its operations at this time.

The United States Congress is considering various legislative proposals that would require generating facilities to comply with more stringent air emissions standards. Emission reduction requirements under consideration would be phased in under a variety of periods of up to 15 years. If these new proposals are adopted, additional significant expenditures may be required.

In July 2004, the EPA published new regulations that govern existing utilities that employ a cooling water intake structure, and whose flow levels exceed a minimum threshold. The EPA’s rule presents several compliance options. The Company is evaluating information from certain of its power stations and expects to spend approximately $14 million over the next four years conducting studies and technical evaluations. The Company cannot predict the outcome of the EPA regulatory process or state with any certainty what specific controls may be required.

The Company has applied for or obtained the necessary environmental permits for the operation of its regulated facilities. Many of these permits are subject to re-issuance and continuing review.

Nuclear Regulatory Commission

All aspects of the operation and maintenance of the Company’s nuclear power stations, which are part of the Generation segment, are regulated by the NRC. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and the operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so requires.

From time to time, the NRC adopts new requirements for the operation and maintenance of nuclear facilities. In many cases, these new regulations require changes in the design, operation and maintenance of existing nuclear facilities. If the NRC adopts such requirements in the future, it could result in substantial increases in the cost of operating and maintaining the Company’s nuclear generating units.

The NRC also requires the Company to decontaminate nuclear facilities once operations cease. This process is referred to as decommissioning, and the Company is required by the NRC to be financially prepared. For information on the Company’s decommissioning trusts, see Generation—Nuclear Decommissioning and Note 8 to the Consolidated Financial Statements.

2004 / Page 5

Item 2. Properties

The Company owns its principal properties in fee (except as indicated below), subject to defects and encumbrances that do not interfere materially with their use. Substantially all of the Company’s property is subject to the lien of the mortgage securing its First and Refunding Mortgage Bonds.

The Company leases its headquarters facility from Dominion. In addition, the Delivery, Energy and Generation segments share certain leased buildings and equipment. See Item 1. Properties for additional information for each segment’s principal properties.

The Generation segment provides electricity for use on a wholesale and a retail level. The Generation segment can supply electricity demand either from its generation facilities in Virginia, North Carolina and West Virginia or through purchased power contracts when needed. The following table lists the Company’s generating units and capability.

Virginia Electric and Power Company’s Power Generation

Plant	Location	Primary Fuel Type	Net Summer Capability (Mw)
North Anna	Mineral, VA	Nuclear	1,628	(a)
Surry	Surry, VA	Nuclear	1,598
Mt. Storm	Mt. Storm, WV	Coal	1,569
Chesterfield	Chester, VA	Coal	1,234
Chesapeake	Chesapeake, VA	Coal	595
Clover	Clover, VA	Coal	441	(b)
Yorktown	Yorktown, VA	Coal	326
Bremo	Bremo Bluff, VA	Coal	227
Mecklenburg	Clarksville, VA	Coal	138
North Branch	Bayard, WV	Coal	74
Altavista	Altavista, VA	Coal	63
Southampton	Southampton, VA	Coal	63
Yorktown	Yorktown, VA	Oil	818
Possum Point	Dumfries, VA	Oil	786
Gravel Neck (CT)	Surry, VA	Oil	183
Darbytown (CT)	Richmond, VA	Oil	144
Chesapeake (CT)	Chesapeake, VA	Oil	144
Possum Point (CT)	Dumfries, VA	Oil	78
Northern Neck (CT)	Lively, VA	Oil	64
Low Moor (CT)	Covington, VA	Oil	60
Kitty Hawk (CT)	Kitty Hawk, NC	Oil	44
Remington (CT)	Remington, VA	Gas	580
Possum Point (CC)	Dumfries, VA	Gas	545	(c)
Chesterfield (CC)	Chester, VA	Gas	397
Possum Point	Dumfries, VA	Gas	322
Elizabeth River (CT)	Chesapeake, VA	Gas	312
Ladysmith (CT)	Ladysmith, VA	Gas	290
Bellmeade (CC)	Richmond, VA	Gas	230
Gordonsville Energy (CC)	Gordonsville, VA	Gas	217
Gravel Neck (CT)	Surry, VA	Gas	146
Darbytown (CT)	Richmond, VA	Gas	144
Bath County	Warm Springs, VA	Hydro	1,477	(d)
Gaston	Roanoke Rapids, NC	Hydro	225
Roanoke Rapids	Roanoke Rapids, NC	Hydro	99
Pittsylvania	Hurt, VA	Other	80
Other	Various	Various	15
			15,356	(e)
Purchased Capacity			3,081	(f)
		Total Capacity	18,437

Note: (CT) denotes combustion turbine and (CC) denotes combined cycle

(a) Excludes 11.6 percent undivided interest owned by Old Dominion Electric Cooperative (ODEC).

(b) Excludes 50 percent undivided interest owned by ODEC.

(c) Generating unit operated by the Company under a leasing arrangement.

(d) Excludes 40 percent undivided interest owned by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc.

(e) Totals may not add due to rounding.

(f) Purchase capacity includes generation from the Batesville facility. The Company has decided to divest its interest in the long-term power tolling contract associated with this facility. See Long-Term Power Tolling Contract in MD&A for additional information.

2004 / Page 6

2004 / Page 7

Item 3. Legal Proceedings

From time to time, the Company is alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by the Company, or permits issued by various local, state and federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on these matters. In addition, in the ordinary course of business, the Company is involved in various legal proceedings. Management believes that the ultimate resolution of these proceedings will not have a material adverse effect on the Company’s financial position, liquidity or results of operations.

See Regulation in Item 1. Business, Future Issues and Other Matters in MD&A and Note 19 to the Consolidated Financial Statements for additional information on rate matters and various regulatory proceedings to which the Company is a party.

Item 4. Submission of Matters to a Vote of Security Holders

None.

Part II

Item 5. Market for the Registrant’s Common Equity and Related Stockholder Matters

Dominion Resources, Inc. (Dominion) owns all of the Company’s common stock.

The Company paid quarterly cash dividends on its common stock as follows:

	Quarter
	1st		2nd		3rd		4th
(millions)
2004	$	126	$	101	$	194	$	97
2003		125		113		213		109

Restrictions on the payment of dividends by the Company are discussed in Note 17 to the Consolidated Financial Statements.

Item 6. Selected Financial Data

	2004(1)		2003(2)			2002		2001(3)		2000(4)
(millions)
Operating revenue	$	5,741	$	5,437		$	4,972	$	4,944	$	4,791
Income before cumulative effect of changes in accounting principles		431		582			773		446		558
Cumulative effect of changes in accounting principles (net of income taxes of $14 in 2003 and $11 in 2000)		—		(21	)		—		—		21
Net income		431		561			773		446		579
Balance available for common stock		415		546			757		423		543
Total assets		17,318		16,884			15,588		14,597		14,282
Long-term debt(5)		4,958		4,744			3,794		3,704		3,561
Preferred securities of subsidiary trust(5)		—		—			400		135		135

(1) 2004 results include: a $112 million after-tax charge reflecting the Company’s valuation of its interest in a long-term power tolling contract; and a $43 million after-tax charge resulting from the termination of long-term power purchase agreements.

(2) 2003 results include: $122 million of after-tax incremental restoration expenses associated with Hurricane Isabel; a $65 million after-tax charge resulting from the termination of long-term power purchase agreements; and a $21 million net after-tax loss for the adoption of accounting standards that resulted in the recognition of the cumulative effect of changes in accounting principles, see Note 3 to the Consolidated Financial Statements.

(3) 2001 results include a $136 million after-tax charge resulting from the termination of long-term power purchase agreements.

(4) 2000 results include a cumulative effect of a change in accounting principle, resulting from a change in the method of calculating the market-related value of pension plan assets.

(5) Upon adoption of Financial Accounting Standards Board Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, on December 31, 2003 with respect to a special purpose entity, the Company began reporting as long-term debt its junior subordinated notes held by the trust, rather than the trust preferred securities issued by the trust. See Note 3 to the Consolidated Financial Statements.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) discusses the results of operations and general financial condition of Virginia Electric and Power Company. MD&A should be read in conjunction with the Consolidated Financial Statements. The “Company” is used throughout MD&A and, depending on the context of its use, may represent any of the following: the legal entity, Virginia Electric and Power Company, one of Virginia Electric and Power Company’s consolidated subsidiaries or the entirety of Virginia Electric and Power Company and its consolidated subsidiaries. The Company is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion).

Contents of MD&A

The MD&A consists of the following information:

• Forward-Looking Statements

• Introduction

• Accounting Matters

• Results of Operations

• Segment Results of Operations

• Selected Information—Energy Trading Activities

• Sources and Uses of Cash

• Future Issues and Other Matters

• Risk Factors and Cautionary Statements That May Affect Future Results

Forward-Looking Statements

This report contains statements concerning the Company’s expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by words such as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may” or other similar words.

The Company makes forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to be materially different from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other risks that may cause actual results to differ from predicted results are set forth in Risk Factors and Cautionary Statements That May Affect Future Results.

2004 / Page 8

The Company bases its forward-looking statements on management’s beliefs and assumptions using information available at the time the statements are made. The Company cautions the reader not to place undue reliance on its forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, materially differ from actual results. The Company undertakes no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.

Introduction

Virginia Electric and Power Company (the Company), a Virginia public service company, is a wholly-owned subsidiary of Dominion. The Company is a regulated public utility that generates, transmits and distributes electricity within an area of approximately 30,000 square-miles in Virginia and northeastern North Carolina. It serves approximately 2.3 million retail customer accounts, including governmental agencies, and wholesale customers such as rural electric cooperatives, municipalities, power marketers and other utilities. The Virginia service area comprises about 65% of Virginia’s total land area, but accounts for over 80% of its population. The Company has trading relationships beyond the geographic limits of its retail service territory where it buys and sells natural gas, electricity and other energy-related commodities.

The Company’s businesses are managed through three operating segments: Generation, Energy and Delivery. The contributions to net income by the Company’s operating segments are determined based on a measure of profit that executive management believes represents the segments’ core earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by executive management in assessing segment performance or allocating resources among the segments. Those specific items are reported in the Corporate and Other segment.

Generation includes the Company’s electric generation operations. The generation mix is diversified and includes coal, nuclear, gas, oil, hydro and purchased power. The Company’s strategy for its electric generation operations focuses on serving customers in Virginia and northeastern North Carolina. Its generation facilities are located in Virginia, West Virginia and North Carolina.

Utility generation operations represent the Generation segment’s source of revenue and cash flows. These operations are sensitive to external factors, primarily weather and fuel prices. Currently, revenue from utility operations largely reflects the capped rates charged to customers in Virginia, the majority of its utility customer base. Under Virginia’s current deregulation legislation, electric base rates are capped through 2010. Under capped rates, changes in the Generation segment’s operating costs, particularly with respect to fuel, relative to costs used to establish the capped rates, will impact the Company’s earnings.

The Company markets its generation resources not needed to serve utility customers as part of its management of utility system resources in the Generation segment.

The Generation segment has reduced costs by terminating certain long-term power purchase agreements.

Variability in expenses for the Generation segment relates primarily to the cost of fuel consumed, labor and benefits, and the timing, duration and costs of scheduled and unscheduled outages.

As a result of the reorganization of the Company’s Clearinghouse operations (Clearinghouse), Generation’s 2004 and 2003 results now reflect revenue and expenses associated with coal trading and marketing activities performed by the Clearinghouse that were previously reported in the Energy segment.

Energy includes a regulated electric transmission system located in Virginia and northeastern North Carolina; and the operations of the Clearinghouse, which are responsible for energy trading (exclusive of marketing excess utility generation), marketing and risk management activities.

The Energy segment’s revenue and cash flows are derived from both regulated and nonregulated operations.

Revenue and cash flows provided by regulated electric transmission operations are based primarily on rates established by the Federal Energy Regulatory Commission (FERC). Variability in revenue and cash flows provided by this business results from fluctuation in rates and the demand for services, which is primarily weather dependent. Variability in expenses relates largely to operating and maintenance expenditures, including decisions regarding use of resources for operations and maintenance or capital-related activities.

Revenue and cash flows for the Energy segment’s Clearinghouse business are subject to variability associated with changes in commodity prices associated with both physical and financial commodity contracts. Certain hedging and trading activities may require cash deposits to satisfy margin requirements. In addition, reported earnings for this segment reflect changes in the fair value of certain derivatives; these values may change significantly from period to period. Variability in expenses for these nonregulated businesses relates largely to labor and benefits and the costs of purchased commodities for resale and payments under financially-settled contracts.

During the fourth quarter of 2004, the Company performed an evaluation of its Clearinghouse trading and marketing operations, which resulted in a decision to exit certain energy trading activities and instead focus on the optimization of company assets. Beginning in 2005, all revenue and expenses from the Clearinghouse’s optimization of company assets will be reported as part of the results of the business segments operating the related assets, in order to better reflect the performance of the underlying assets. As a result of these changes, 2004 and 2003 results now reflect revenue and expenses associated with coal trading and marketing activities in the Generation segment.

Delivery includes the Company’s electric distribution system and customer service operations. The electric distribution system serves residential, commercial, industrial and governmental customers in Virginia and northeastern North Carolina.

Revenue and cash flows provided by electric distribution operations are based primarily on rates established by state regulatory authorities and state law. Variability in the Delivery segment’s revenue and cash flows relates largely to changes in sales volumes, which are primarily weather sensitive.

Variability in expenses results from changes in the cost of routine maintenance and repairs (including labor and benefits as

2004 / Page 9

well as decisions regarding the use of resources for operations and maintenance or capital-related activities).

Corporate and Other includes the Company’s corporate and other functions and specific items attributable to the Company’s operating segments that are reported in Corporate and Other.

Accounting Matters

Critical Accounting Policies and Estimates

The Company has identified the following accounting policies, including certain inherent estimates, that as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and operations involved, could result in material changes to its financial condition or results of operations under different conditions or using different assumptions. Management has discussed the development, selection and disclosure of each of these policies with the Company’s Audit Committee.

Accounting for derivative contracts at fair value

The Company uses derivative contracts (primarily forward purchases and sales, swaps, options and futures) to buy and sell energy-related commodities and to manage its commodity and financial market risks. Derivative contracts, with certain exceptions, are subject to fair value accounting and are reported on the Consolidated Balance Sheets at fair value. Accounting requirements for derivatives and related hedging activities are complex and may be subject to further clarification by standard-setting bodies.

Fair value of derivatives is based on actively quoted market prices, if available. In the absence of actively quoted market prices, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, the Company must estimate prices based on available historical and near-term future price information and use of statistical methods. For options and contracts with option-like characteristics where pricing information is not available from external sources, the Company generally uses a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions. The Company uses other option models when contracts involve different commodities or commodity locations and when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts with unique characteristics, the Company estimates fair value using a discounted cash flow approach. If pricing information is not available from external sources, judgment is required to develop estimates of fair value. For individual contracts, the use of different valuation models or assumptions could have a material effect on the contract’s estimated fair value.

For cash flow hedges of forecasted transactions, the Company must estimate the future cash flows represented by the forecasted transactions, as well as evaluate the probability of occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could require discontinuance of hedge accounting or could affect the timing for reclassification of gains or losses on cash flow hedges from accumulated other comprehensive income (loss) (AOCI) into earnings.

Use of estimates in long-lived asset impairment testing

Impairment testing for an individual or group of long-lived assets or intangible assets with definite lives is required when circumstances indicate those assets may be impaired. When an asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. Performing an impairment test on long-lived assets involves management’s judgment in areas such as identifying circumstances indicating an impairment may exist, identifying and grouping affected assets and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of market-based value) associated with the asset, including the selection of an appropriate discount rate. Although cash flow estimates used by the Company would be based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. For example, estimates of future cash flows would contemplate factors such as the expected use of the asset, including future production and sales levels, and expected fluctuations of prices of commodities sold and consumed. During 2004, the Company did not test any significant long-lived assets or asset groups for impairment as no circumstances arose that indicated an impairment may exist.

Asset retirement obligations

The Company recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These asset retirement obligations (AROs) are recognized at fair value as incurred, and are capitalized as part of the cost of the related tangible long-lived assets. In the absence of quoted market prices, the Company estimates the fair value of its AROs using present value techniques, in which the Company makes various assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. AROs currently reported on the Company’s Consolidated Balance Sheets were measured during a period of historically low interest rates. The impact on measurements of new AROs, using different rates in the future, may be significant. The Company did not recognize any new, significant AROs in 2004. In the future, if the Company revises any assumptions used to calculate the fair value of existing AROs, the Company will adjust the carrying amount of both the ARO liability and related long-lived asset. The Company records accretion expense, increasing the ARO liability, with the passage of time. In 2004 and 2003, the Company recognized $42 million and $38 million, respectively, of accretion expense, and expects to incur $45 million in 2005.

A significant portion of the Company’s AROs relate to the future decommissioning of its nuclear facilities. At December 31, 2004, nuclear decommissioning AROs, which are reported in the Generation segment, totaled $755 million, representing approximately 97% of the Company’s total AROs. Based on their significance, the following discussion of critical assumptions inherent

2004 / Page 10

in determining the fair value of AROs relates to those associated with the Company’s nuclear decommissioning obligations.

The Company obtains from third-party experts periodic site-specific “base year” cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for its nuclear plants. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods are by nature highly uncertain and may vary significantly from actual results. In addition, these cost estimates are dependent on subjective factors, including the selection of cost escalation rates, which the Company considers to be a critical assumption.

The Company determines cost escalation rates, which represent projected cost increases over time, due to both general inflation and increases in the cost of specific decommissioning activities, for each of its nuclear facilities. The weighted average cost escalation used by the Company was 3.28%. The use of alternative rates would have been material to the liabilities recognized. For example, had the Company increased the cost escalation rate by 0.5% to 3.78%, the amount recognized as of December 31, 2004 for its AROs related to nuclear decommissioning would have been $148 million higher.

Accounting for regulated operations

The Company’s accounting for its regulated electric operations differs from the accounting for nonregulated operations in that the Company is required to reflect the effect of rate regulation in its Consolidated Financial Statements. Specifically, the Company’s regulated operations record assets and liabilities that nonregulated companies would not report under accounting principles generally accepted in the United States of America. When it is probable that regulators will allow for the recovery of current costs through future rates charged to customers, the Company defers these costs that otherwise would be expensed by nonregulated companies and recognizes regulatory assets in its financial statements. Likewise, the Company recognizes regulatory liabilities in its financial statements when it is probable that regulators will allow for customer credits through future rates and when revenue is collected from customers for expenditures that are not yet incurred.

Management evaluates whether or not recovery of its regulatory assets through future regulated rates is probable and makes various assumptions in its analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If recovery of regulatory assets is determined to be less than probable, the regulatory asset will be written off and an expense will be recorded in the period such assessment is made. Management currently believes the recovery of its regulatory assets is probable. See Notes 2 and 11 to the Consolidated Financial Statements.

Income Taxes

Judgment is required in developing the Company’s provision for income taxes, including the determination of deferred tax assets and any related valuation allowance. The Company evaluates the probability of realizing its deferred tax assets on a quarterly basis by reviewing its forecast of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies might affect the ultimate realization of deferred tax assets.

Newly Adopted Accounting Standards

During 2004 and 2003, the Company was required to adopt several new accounting standards, the requirements of which are discussed in Notes 2 and 3 to the Consolidated Financial Statements. The accounting standards adopted during 2003 affect the comparability of the Company’s Consolidated Statements of Income. The following discussion is presented to provide an understanding of the impacts of those standards on that comparability.

FIN 46R

The adoption of Financial Accounting Standards Board (FASB) Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, (FIN 46R) on December 31, 2003 with respect to special purpose entities, affected the comparability of the Company’s 2004 Consolidated Statement of Income to prior years as follows:

• The Company was required to consolidate a variable interest lessor entity through which the Company had financed and leased a new power generation project. As a result, the Consolidated Balance Sheet as of December 31, 2003 reflects an additional $364 million in net property, plant and equipment and deferred charges and $370 million of related debt. In 2004, the Company’s Consolidated Statement of Income reflects depreciation expense on the net property, plant and equipment and interest expense on the debt associated with this variable interest lessor entity, whereas in prior years, it reflected as rent expense in other operations and maintenance expense, the lease payments to this entity; and

• In addition, under FIN 46R, the Company reports as long-term debt its junior subordinated notes held by a capital trust rather than the trust preferred securities issued by the trust. As a result, in 2004, the Company reported interest expense on the junior subordinated notes rather than preferred distribution expense on the trust preferred securities.

SFAS No. 143

Adopting Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, on January 1, 2003 affected the comparability of the Company’s 2004 and 2003 Consolidated Statements of Income to the prior year as follows:

• Accretion of the AROs for nuclear decommissioning is reported in other operations and maintenance expense. Previously, expenses associated with the provision for nuclear decommissioning were reported in depreciation expense and in other income (loss); and

• Realized and unrealized earnings of trusts available for funding decommissioning activities at the Company’s nuclear plants are recorded in other income (loss) and AOCI, as appropriate. Previously, as permitted by regulatory authorities, these earnings, along with an offsetting charge to expense for the accretion of the decommissioning liability, were both reported in other income (loss).

2004 / Page 11

EITF 02-3 and 03-11

The adoption of Emerging Issues Task Force (EITF) Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, and related EITF Issue No. 03-11, Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes” as Defined in Issue No. 02-3, changed the timing of recognition in earnings for certain Clearinghouse energy-related contracts, as well as the financial statement presentation of gains and losses associated with energy-related contracts. The Consolidated Statement of Income for 2002 was not restated. Prior to 2003, all energy trading contracts, including non-derivative contracts, were recorded at fair value with changes in fair value and settlements reported in revenue on a net basis. Specifically, adopting EITF 02-3 and 03-11 affected the comparability of the Company’s 2004 and 2003 Consolidated Statements of Income to the prior year as follows:

• For derivative contracts not held for trading purposes that involve physical delivery of commodities, unrealized gains and losses and settlements on sales contracts are presented in revenue, while unrealized gains and losses and settlements on purchase contracts are reported in expense; and

• Non-derivative energy-related contracts, previously subject to fair value accounting under prior accounting guidance, are recognized as revenue or expense on a gross basis at the time of contract performance, settlement or termination.

Results of Operations

Presented below is a summary of contributions by the Company’s operating segments to net income:

	Year Ended December 31,
	2004			2003			2002
(millions)
Generation	$	407		$	406		$	486
Energy		(109	)		100			28
Delivery		288			282			255
Operating segments		586			788			769
Corporate and Other		(155	)		(227	)		4
Consolidated	$	431		$	561		$	773

Overview

2004 vs. 2003

Net income decreased 23% to $431 million, as compared to 2003, primarily reflecting:

• A slightly higher contribution from utility generation operations, primarily resulting from the combined effects of the following:

• Favorable margins in coal trading and marketing activities;

• A reduction in capacity expenses due to the termination of certain long-term power purchase agreements; and

• Increased revenue due to favorable weather and customer growth; largely offset by

• The elimination of fuel deferral accounting for the Virginia jurisdiction, which resulted in the recognition of fuel expenses in excess of amounts recovered in fixed fuel rates.

• A net loss from energy trading and marketing activities, resulting primarily from the effects of:

• Unfavorable price changes on electric trading margins;

• The transfer of certain wholesale electric contracts to a Dominion subsidiary in 2003;

• Comparatively lower price volatility on natural gas option positions; and

• Net losses associated with the settlement of a portfolio of financial derivatives held as economic hedges for a portion of Dominion’s 2004 natural gas production.

The decrease in net income was also impacted by the following specific items recognized in 2004 and reported in the Corporate and Other segment:

• A $112 million after-tax charge, reflecting the Company’s valuation of its interest in a long-term power tolling contract, which is subject to a planned divestiture in the first quarter of 2005, as a result of its exit from certain energy trading activities. The charge is based on the Company’s evaluation of preliminary bids received from third parties, reflecting the expected amount of consideration that would be required by a third party for its assumption of the Company’s interest in the contract;

• $43 million net after-tax charges resulting from the termination of certain long-term power purchase agreements; and

• A $7 million after-tax charge related to an agreement to settle a class action lawsuit involving a dispute over the Company’s rights to lease fiber-optic cable along a portion of its electric transmission corridor; partially offset by

• An $11 million after-tax benefit to adjust expenses accrued in 2003 associated with restoration activities related to Hurricane Isabel.

In addition, the decrease in net income was impacted by the specific items recognized in 2003 and reported in the Corporate and Other segment, as described below.

2004 / Page 12

2003 vs. 2002

Net income decreased 27% to $561 million, as compared to 2002, primarily reflecting:

• A lower contribution from utility generation operations, primarily due to comparably milder weather, recognition of previously deferred fuel costs in connection with the settlement of the Virginia jurisdictional fuel rate case, and increased nuclear refueling outage expenses at the Company’s nuclear generating units, partially offset by customer growth in the electric franchise service area and a reduction in capacity expenses due to termination of certain long-term power purchase agreements;

• A higher contribution from Clearinghouse operations associated with increased margins on settled contracts and lower net losses associated with the settlement of a portfolio of financial derivatives held as economic hedges for a portion of Dominion’s 2003 natural gas production; and

• A higher contribution from distribution operations, primarily resulting from customer growth in the electric franchise service area, partially offset by comparably milder weather and an increase in pension and other postretirement benefit costs.

The decrease in net income was also impacted by the following specific items recognized in 2003 and reported in the Corporate and Other segment:

• $122 million after-tax incremental restoration expenses associated with Hurricane Isabel;

• A $65 million after-tax charge resulting from the termination of two long-term power purchase agreements;

• $12 million after-tax charges associated with the restructuring of power sales contracts;

• $5 million after-tax severance costs associated with workforce reductions; and

• A $21 million net after-tax loss for the cumulative effect of changes in accounting principles, resulting from the adoption of the following new accounting standards:

• $139 million after-tax gain—adoption of SFAS No. 143;

• $101 million after-tax loss—adoption of SFAS No. 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;

• $55 million after-tax loss—adoption of EITF 02-3; and

• $4 million after-tax loss—adoption of FIN 46R.

Analysis of Consolidated Operations

Presented below are selected amounts related to the Company’s results of operations:

	Year Ended December 31,
	2004			2003			2002
(millions)
Operating Revenue
Regulated electric sales	$	5,180		$	4,876		$	4,857
Nonregulated electric sales		(141	)		44			78
Nonregulated gas sales		42			263			(58	)
Other		660			254			95
Operating Expenses
Electric fuel and energy purchases, net		1,750			1,472			1,281
Purchased electric capacity		550			607			691
Purchased gas		110			115			—
Other purchased energy commodities		518			189			—
Other operations and maintenance		1,295			1,284			893
Depreciation and amortization		496			458			495
Other taxes		169			173			152
Other income		71			81			32
Interest and related charges		254			302			294
Income tax expense		239			336			425
Cumulative effect of changes in accounting principles (net of income taxes)		—			(21	)		—

An analysis of the Company’s results of operations for 2004 compared to 2003 and 2003 compared to 2002 follows:

2004 vs. 2003

Operating Revenue

Regulated electric sales revenue increased 6% to $5.2 billion, primarily reflecting:

• A $231 million increase due to the impact of a comparatively higher fuel rate on increased sales volumes. The rate increase resulted from the settlement of a fuel rate case in December 2003 and was more than offset by an increase in Electric fuel and energy purchases, net expense;

• A $49 million increase associated with new customer connections;

• A $24 million increase associated with comparably favorable weather; and

• An $18 million increase due to lost revenue in 2003 as a result of outages caused by Hurricane Isabel.

Nonregulated electric sales revenue decreased 420% to a negative $141 million, reflecting a decrease in energy trading and marketing activities, resulting primarily from:

• $122 million of losses primarily resulting from energy trading and marketing activities, reflecting decreased margins in electric trading due to unfavorable price movements; and

2004 / Page 13

• $142 million decline in trading revenue due to the transfer of certain wholesale electric contracts to a Dominion subsidiary in 2003 combined with $42 million higher margins due to unfavorable price changes in 2003 on those transferred wholesale electric contracts; partially offset by

• A $58 million increase from the sale of excess generation and higher margins on electric trading.

Nonregulated gas sales revenue decreased 84% to $42 million, reflecting a decrease in energy trading and marketing activities, resulting primarily from:

• $130 million of losses related to certain natural gas contracts held in connection with management of storage and transportation agreements;

• A $52 million net loss associated with a portfolio of financial derivatives held as economic hedges for a portion of Dominion’s 2004 natural gas production; and

• A $44 million loss from comparatively lower price volatility on natural gas option positions.

Other revenue increased 160% to $660 million, primarily reflecting a $384 million increase in coal sales, resulting from higher coal prices and increased sales volumes. The increase in coal sales revenue was largely offset by an increase in the cost of coal purchased for resale reported in Other purchased energy commodities expense.

Operating Expenses and Other Items

Electric fuel and energy purchases, net expense increased 19% to $1.8 billion, primarily reflecting:

• A $408 million increase related to utility generation operations, resulting from the combined effects of an increase in the fixed fuel rate and the elimination of fuel deferral accounting for the Virginia jurisdiction, which resulted in the recognition of fuel expenses in excess of amounts recovered in fixed fuel rates. The increase also reflected higher generation volumes in the current year; partially offset by

• A $130 million decrease primarily associated with the transfer of certain wholesale electric contracts to a Dominion subsidiary in 2003.

Purchased electric capacity expense decreased 9% to $550 million, primarily resulting from the termination of certain long-term power purchase agreements as a result of the purchase of the related non-utility generating facilities.

Other purchased energy commodities expense increased 174% to $518 million, primarily reflecting an increase in the cost of coal purchased for resale.

Depreciation and amortization expense increased 8% to $496 million, due to incremental expense resulting from property additions, including the consolidation of the variable interest lessor entity as a result of adopting FIN 46R at December 31, 2003.

Other income decreased 12% to $71 million, primarily reflecting lower net realized gains (including investment income) associated with nuclear decommissioning trust fund investments.

Interest and related charges decreased 16% to $254 million, primarily due to refinancing of callable mortgage bonds with lower cost unsecured debt in December 2003.

2003 vs. 2002

Operating Revenue

Regulated electric sales revenue increased less than 1% to $4.9 billion, primarily reflecting the following:

• A $54 million increase representing customer growth associated with new customer connections; and

• A $42 million increase resulting from fuel rate recoveries. Fuel rate recoveries were generally offset by a comparable increase in fuel expense and did not materially affect net income. These increases were partially offset by:

• A $103 million decrease associated with milder weather; and

• Decreases in sales revenue due to hurricane-related outages.

Nonregulated gas sales revenue increased 561% to $263 million, reflecting higher margins in Clearinghouse gas sales, net of applicable purchases, due to favorable changes in the fair value of derivative contracts held for trading purposes and the impact of adopting EITF 02-3. The increase included $54 million associated with a portfolio of financial derivatives held as economic hedges for a portion of Dominion’s 2003 natural gas production.

Other revenue increased 167% to $254 million, reflecting:

• A $52 million increase in coal sales revenue; and

• A $115 million increase resulting from a change in the classification of coal purchases from other revenue to expense under EITF 02-3 beginning in 2003.

Operating Expenses and Other Items

Electric fuel and energy purchases, net expense increased 15% to $1.5 billion, primarily reflecting:

• A $123 million increase associated with nonregulated energy trading operations, primarily resulting from higher volumes purchased and the reclassification of certain purchase contracts due to the implementation of EITF 02-3; and

• A $68 million increase related to regulated operations, including $42 million associated with rate recoveries and the recognition of $14 million of previously deferred fuel costs that will not be recovered under the 2003 settlement of the Virginia jurisdictional fuel rate case.

Purchased electric capacity expense decreased 12% to $607 million, reflecting scheduled rate reductions on certain non-utility generation power purchase agreements ($54 million) and lower purchases of capacity for utility operations ($30 million), resulting from the termination of certain long-term power purchase agreements.

Purchased gas expense was $115 million, representing the cost of supplies used to serve nonregulated gas sales.

Other purchased energy commodities expense was $189 million, reflecting the reclassification of certain purchase contracts for transportation, storage and coal due to the adoption of EITF 02-3.

Other operations and maintenance expense rose 44% to $1.3 billion, primarily reflecting the impact of the following 2003 items:

• Incremental restoration expenses associated with Hurricane Isabel ($197 million);

• Cost of terminating two long-term power purchase agreements used in electric utility operations ($105 million);

• A charge associated with the restructuring of certain electric sales contracts ($21 million);

2004 / Page 14

• Accretion expense for AROs ($38 million); and

• Expenses associated with nuclear refueling outages ($15 million).

Depreciation and amortization expense decreased 7% to $458 million, primarily reflecting the change in the presentation of expenses associated with AROs.

Other taxes expense increased 14% to $173 million, primarily due to the effect of a favorable resolution of sales and use tax issues in 2002. Such benefits were not recognized in 2003.

Other income increased 153% to $81 million, primarily reflecting net realized gains (including investment income of $34 million) associated with nuclear decommissioning trust fund investments.

Cumulative effect of changes in accounting principles—During 2003, the Company was required to adopt several new accounting standards, resulting in a net after-tax loss of $21 million, which included the following:

• A $139 million after-tax gain (SFAS No. 143);

• A $101 million after-tax loss (SFAS No. 133 Implementation Issue No. C20);

• A $55 million after-tax loss (EITF 02-3); and

• A $4 million after-tax loss (FIN 46R).

Outlook

The Company believes its operating businesses will provide stable growth in net income in 2005. The following are growth factors that will impact these expected results:

• Continued growth in utility customers; and

• Reduced electric capacity expenses, resulting from the termination of long-term power purchase agreements.

The growth factors in 2005 will be impacted by:

• Higher expected Virginia jurisdictional fuel expenses; and

• Increased interest expense.

Based on these projections, the Company estimates that cash flows from operations will increase in 2005, as compared to 2004. Management believes this increase will provide sufficient cash flows to maintain or grow the Company’s current dividend to Dominion.

Segment Results of Operations

Generation

Generation includes the Company’s portfolio of electric generating facilities, power purchase agreements, marketing of its excess generation resources and coal trading and marketing activities.

	Year Ended December 31,
	2004		2003		2002
(millions)
Net income contribution	$	407	$	406	$	486
Electricity supplied (million mwhrs)		79		76		76

mmwhrs = megawatt hours

The Generation segment provides electricity primarily from nuclear, coal, oil, purchased power and natural gas. Presented below is a summary of the system’s energy output by energy source.

	2004		2003		2002
Nuclear(1)	32	%	29	%	32	%
Coal(2)	38		38		42
Oil	6		6		4
Purchased Power, net	19		23		19
Natural Gas(3)	5		3		3
Other	—		1		—
Total	100	%	100	%	100	%

(1) Nuclear mix excludes Old Dominion Electric Cooperative’s (ODEC) 11.6% ownership interest in the North Anna Power Station.

(2) Coal mix excludes ODEC’s 50% ownership interest in the Clover Power Station.

(3) Includes natural gas used in combustion turbines that are fueled by gas.

Presented below, on an after-tax basis, are the key factors impacting the Generation segment’s operating results:

2004 vs. 2003

	Increase (Decrease)
(millions)
Fuel expenses in excess of rate recovery	$	(115	)
Capacity expenses		36
Coal trading and marketing		31
Customer growth		20
Weather		10
Interest expense		9
Lost revenue due to Hurricane Isabel		7
Other		3
Change in net income contribution	$	1

Generation’s net income increased $1 million, primarily reflecting the following:

• Higher fuel expenses due to the elimination of fuel deferral accounting for the Virginia jurisdiction, which resulted in the recognition of fuel expenses in excess of amounts recovered in fixed fuel rates. The increase in fuel expenses also reflects higher generation volumes;

• Reduced purchased power capacity expenses due to the termination of certain long-term power purchase agreements in connection with the purchase of the related non-utility generating facilities;

• A higher contribution from coal trading and marketing, primarily due to higher coal prices and increased sales volumes;

2004 / Page 15

• An increase in regulated electric sales revenue due to customer growth in the electric franchise service area, primarily in residential and commercial customer connections;

• An increase in regulated electric sales revenue from comparably favorable weather;

• Lower interest expense due to refinancing of callable mortgage bonds with lower cost unsecured debt in December 2003;

• An increase in regulated electric sales revenue due to lost revenue in 2003 associated with outages related to Hurricane Isabel; and

• Other factors including the impact of economic conditions on customer usage.

2003 vs. 2002

	Increase (Decrease)
(millions)
Revenue reallocation	$	(57	)
Weather		(42	)
Capacity expenses		29
Customer growth		22
Utility outages		(11	)
Fuel rate case settlement		(9	)
Other		(12	)
Change in net income contribution	$	(80	)

Generation had a decrease of $80 million in net income, primarily reflecting the following:

• A change in the allocation of electric base rate revenue among the Generation, Energy and Delivery segments effective January 1, 2003;

• A decrease in regulated electric sales due to comparably unfavorable weather;

• Scheduled decreases in capacity expenses under certain long-term power purchase agreements;

• An increase in regulated electric sales due to customer growth in the electric franchise service area, primarily reflecting an increase in new residential customers;

• Increased outage expenses, reflecting refueling outages in 2003 at the Company’s nuclear generating units; and

• Recognition of previously deferred fuel costs in connection with the 2003 Virginia rate settlement.

Energy

Energy includes the Company’s electric transmission and energy trading and marketing operations.

	Year Ended December 31,
	2004			2003		2002
(millions)
Net income (loss)	$	(109	)	$	100	$	28

Presented below, on an after-tax basis, are the key factors impacting the Energy segment’s operating results:

2004 vs. 2003

	Increase (Decrease)
(millions)
Energy trading and marketing activities	$	(184	)
Economic hedges		(12	)
Electric transmission revenue		(15	)
Other		2
Change in net income contribution	$	(209	)

Energy had a net loss of $109 million in 2004, as compared to net income of $100 million in 2003, primarily reflecting:

• A net loss from energy trading and marketing activities, resulting primarily from the effects of unfavorable price changes on electric trading margins, the transfer of certain wholesale electric contracts to a Dominion subsidiary in 2003 and comparatively lower price volatility on natural gas option positions;

• A decrease attributable to unfavorable price movements associated with a portfolio of financial derivatives held as economic hedges for a portion of Dominion’s 2004 natural gas production; and

• Lower electric transmission revenue, primarily due to decreased wheeling revenue resulting from lower contractual volumes and unfavorable market conditions.

2003 vs. 2002

	Increase (Decrease)
(millions)
Economic hedges	$	33
Energy trading and marketing activities		21
Electric transmission margins		11
Revenue reallocation		7
Change in net income contribution	$	72

Energy’s net income contribution increased $72 million, primarily reflecting:

• Lower net losses associated with a portfolio of financial derivatives held by the Clearinghouse held as economic hedges on behalf of Dominion in connection with price risk management for a portion of its future sales of natural gas production;

• An increase in the contribution of energy trading and marketing activities, reflecting increased margins on settled contracts, partially offset by a decrease in net mark-to-market gains on derivative contracts;

• An increase in electric transmission margins due to customer growth and other factors, partially offset by the impact of unfavorable weather; and

• A change in the allocation of electric base rate revenue among the operating segments effective January 1, 2003.

2004 / Page 16

Delivery

Delivery includes the Company’s electric distribution system and customer service operations.

	Year Ended December 31,
	2004		2003		2002
(millions)
Net income contribution	$	288	$	282	$	255
Electricity delivered to utility customers (million mwhrs)		78		75		75

Presented below, on an after-tax basis, are the key factors impacting the Delivery segment’s operating results:

2004 vs. 2003

	Increase (Decrease)
(millions)
Interest expense	$	14
Reliability expenses		(11	)
Customer growth		9
Weather		4
Other		(10	)
Change in net income contribution	$	6

Delivery’s net income contribution increased $6 million, reflecting:

• Lower interest expense due primarily to refinancing of callable mortgage bonds with lower cost unsecured debt in December 2003;

• Higher reliability expenses, primarily due to increased tree trimming;

• An increase in regulated electric sales revenue due to customer growth in the electric franchise service area, primarily reflecting new residential customers;

• An increase in regulated electric sales revenue from comparably favorable weather; and

• Other factors, including an increase in pension expense.

2003 vs. 2002

	Increase (Decrease)
(millions)
Revenue reallocation	$	50
Weather		(19	)
Customer growth		10
Other		(14	)
Change in net income contribution	$	27

Delivery’s net income contribution increased $27 million, reflecting:

• A change in the allocation of electric base rate revenue among the operating segments effective January 1, 2003;

• A decrease in regulated electric sales due to comparably milder weather;

• An increase in regulated electric sales due to customer growth in the electric franchise service area, primarily reflecting new residential customers; and

• Other factors, including an increase in pension and other postretirement benefit costs.

Corporate and Other

Corporate and Other includes the Company’s corporate and other functions and specific items.

Presented below are the Corporate and Other segment’s after-tax operating results:

	Year Ended December 31,
	2004			2003			2002
(millions)
Cumulative effect of changes in accounting principles	$	—		$	(21	)	$	—
Specific items attributable to operating segments		(155	)		(204	)		4
Other		—			(2	)		—
Net income (loss)	$	(155	)	$	(227	)	$	4

2004

The Company reported in the Corporate and Other segment (in other operations and maintenance expense) the following specific items attributable to its operating segments:

• A $184 million ($112 million after-tax) charge related to the valuation of the Company’s interest in a long-term power tolling contract (Generation);

• $71 million ($43 million after-tax) of losses from the termination of three long-term power purchase agreements (Generation); and

• A $12 million ($7 million after-tax) charge related to an agreement to settle a class action lawsuit involving a dispute over the Company’s rights to lease fiber-optic cable along a portion of its electric transmission corridor (Energy); partially offset by

• An $18 million ($11 million after-tax) benefit to adjust expenses accrued in 2003 associated with restoration activities related to Hurricane Isabel (Delivery).

2003

The Company reported in the Corporate and Other segment (in other operations and maintenance expense) the following specific items attributable to its operating segments:

• A $21 million net after-tax loss for the cumulative effect of changes in accounting principles, resulting from the adoption of the following new accounting standards:

• $139 million after-tax gain—adoption of SFAS No. 143 ($140 million after-tax gain—Generation and $1 million after-tax loss—Delivery);

2004 / Page 17

• $101 million after-tax loss—adoption of Statement 133 Implementation Issue No. C20 (Generation);

• $55 million after-tax loss—adoption of EITF 02-3 (Energy); and

• $4 million after-tax loss—adoption of FIN 46R (Generation).

• $197 million ($122 million after-tax) of incremental restoration expenses associated with Hurricane Isabel: $119 million (Delivery), $2 million (Energy) and $1 million (Generation);

• A $105 million ($65 million after-tax) charge resulting from the termination of two long-term power purchase agreements (Generation);

• $21 million ($12 million after-tax) of charges associated with the restructuring of power sales contracts (Generation); and

• $8 million ($5 million after-tax) of severance costs associated with workforce reductions: $5 million (Delivery) and $3 million (Generation).

Selected Information—Energy Trading Activities

As previously described, the Company manages its energy trading and risk management activities through the Clearinghouse. The Company believes these operations complement its integrated energy businesses and facilitate its risk management activities. As part of these operations, the Clearinghouse enters into contracts for purchases and sales of energy-related commodities, including coal, natural gas and oil. During 2003 and prior periods, the Company’s Clearinghouse operations also included contracts for purchases and sales of electricity. In connection with Dominion’s plan to conduct its non-utility wholesale electric marketing and trading activities through another Dominion subsidiary, the Company assigned certain wholesale electric contracts that are not supplied from its own generation resources and involve activities outside of its service territory. The Company will continue to market its generation resources not needed to serve utility customers but will do so as part of its management of utility system resources in the Generation segment rather than through its Clearinghouse operations.

Settlement of a contract may require physical delivery of the underlying commodity or cash settlement. The Clearinghouse enters into contracts with the objective of benefiting from changes in prices. For example, after entering into a contract to purchase a commodity, the Clearinghouse typically enters into a sales contract, or a combination of sales contracts, with quantities and delivery or settlement terms that are identical or very similar to those of the purchase contract. When the purchase and sales contracts are settled either by physical delivery of the underlying commodity or by net cash settlement, the Clearinghouse may receive a net cash margin (a realized gain), or may pay a net cash margin (a realized loss). Clearinghouse management continually monitors its contract positions, considering location and timing of delivery or settlement for each energy commodity in relation to market price activity, seeking arbitrage opportunities.

During the fourth quarter of 2004, the Company performed an evaluation of its Clearinghouse trading and marketing operations, which resulted in a decision to exit certain energy trading activities and instead focus on the optimization of company assets. Beginning in 2005, all revenue and expenses from the Clearinghouse’s optimization of company assets will be reported as part of the results of the business segments operating the related assets.

A summary of the changes in the unrealized gains and losses recognized for the Company’s energy-related derivative instruments held for trading purposes during 2004 follows:

	Amount
(millions)
Net unrealized loss at December 31, 2003	$	(45	)
Contracts realized or otherwise settled during the period		52
Net unrealized gain at inception of contracts initiated during the period		—
Other changes in fair value		(42	)
Changes in valuation techniques		—
Net unrealized loss at December 31, 2004	$	(35	)

The balance of net unrealized gains and losses recognized for the Company’s energy-related derivative instruments held for trading purposes, at December 31, 2004, is summarized in the following table based on the approach used to determine fair value and contract settlement or delivery dates:

	Maturity Based on Contract Settlement or Delivery Date(s)
Source of Fair Value	Less Than 1 Year			1-2 Years			2-3 Years			3-5 Years		In Excess of 5 Years	Total
(millions)
Actively quoted(1)	$	(27	)	$	(1	)	$	5		$	—	—	$	(23	)
Other external sources(2)		—			(7	)		(7	)		2	—		(12	)
Models and other valuation methods(3)		—			—			—			—	—		—
Total	$	(27	)	$	(8	)	$	(2	)	$	2	—	$	(35	)

(1) Exchange-traded and over-the-counter contracts.

(2) Values based on prices from over-the-counter broker activity and industry services and, where applicable, conventional option pricing models.

(3) Values based on the Company’s estimate of future commodity prices when information from external sources is not available and use of internally-developed models, reflecting option pricing theory, discounted cash flow concepts, etc.

Sources and Uses of Cash

The Company depends on both internal and external sources of liquidity to provide working capital and to fund capital requirements. Short-term cash requirements not met by cash provided by operating activities are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through sales of securities and additional long-term financing.

At December 31, 2004, the Company had cash and cash equivalents of $2 million with $1.5 billion of unused capacity under its credit facilities. For long-term financing needs, amounts available for debt or equity offerings under currently effective shelf registrations totaled $670 million at February 1, 2005.

2004 / Page 18

Operating Cash Flows

As presented on the Company’s Consolidated Statements of Cash Flows, net cash flows from operating activities were $1.2 billion in 2004, $1.2 billion in 2003 and $1.3 billion in 2002. Management believes that its operations provide a stable source of cash flow sufficient to contribute to planned levels of capital expenditures and maintain or grow current dividends payable to Dominion.

The Company’s operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows, including:

• Cost-recovery shortfalls due to capped base and fuel rates in effect in Virginia for the utility generation business;

• Unusual weather and its effect on energy sales to customers and energy commodity prices;

• Extreme weather events that could disrupt or cause catastrophic damage to the Company’s electric distribution and transmission systems;

• Exposure to unanticipated changes in prices for energy commodities purchased or sold, including the effect on derivative instruments that may require the use of funds to post margin deposits with counterparties;

• Effectiveness of the Company’s risk management activities and underlying assessment of market conditions and related factors, including energy commodity prices, basis, liquidity, volatility, counterparty credit risk, availability of generation and transmission capacity, currency exchange rates and interest rates;

• The cost of replacement of electric energy in the event of longer-than-expected or unscheduled generation outages; and

• Contractual or regulatory restrictions on transfers of funds among the Company and Dominion and its subsidiaries.

Credit Risk

The Company’s exposure to potential concentrations of credit risk results primarily from its energy trading and risk management activities. Presented below is a summary of the Company’s gross and net credit exposure as of December 31, 2004 for these activities. The Company calculates its gross credit exposure for each counterparty as the unrealized fair value of derivative contracts plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral.

	December 31, 2004
	Gross Credit Exposure		Credit Collateral		Net Credit Exposure
(millions)
Investment grade(1)	$	425	$	17	$	408
Non-investment grade(2)		2		1		1
No external ratings:
Internally rated—investment grade(3)		249		—		249
Internally rated—non-investment grade(4)		19		—		19
Total	$	695	$	18	$	677

(1) Designations as investment grade are based on minimum credit ratings assigned by Moody’s Investors Service (Moody’s) and Standard & Poor’s Rating Group, a division of the McGraw-Hill Companies, Inc. (Standard & Poor’s). The five largest counterparty exposures, combined, for this category, represented approximately 22% of the total gross credit exposure.

(2) The five largest counterparty exposures, combined, for this category, represented less than 1% of the total gross credit exposure.

(3) The five largest counterparty exposures, combined, for this category, represented approximately 26% of the total gross credit exposure.

(4) The five largest counterparty exposures, combined, for this category, represented approximately 2% of the total gross credit exposure.

Investing Cash Flows

During 2004, 2003 and 2002, the Company’s investing activities resulted in net cash outflows of $876 million, $1.1 billion and $857 million, respectively. Significant investing activities for 2004 included $96 million for nuclear fuel expenditures and $761 million for plant construction and other property additions detailed as follows:

• $327 million on generation-related projects, including environmental upgrades and routine capital improvements;

• $122 million on transmission-related projects, reflecting construction and improvements;

• $286 million on distribution-related projects, reflecting routine capital improvements and expenditures associated with new connections; and

• $26 million for other general and information technology projects.

Investing activities for 2004 also included $277 million for purchases of securities and $237 million from sales of securities related to investments held in the Company’s nuclear decommissioning trusts.

Financing Cash Flows and Liquidity

The Company relies on access to bank and capital markets as a significant source of funding for capital requirements not satisfied by the cash provided by the Company’s operations. As discussed in the Credit Ratings below, the Company’s ability to borrow funds or issue securities and the return demanded by investors are affected by the Company’s credit ratings. In addition, the raising of external capital is subject to certain regulatory approvals, including authorization by the Virginia State Corporation Commission (Virginia Commission).

During 2004, 2003 and 2002, net cash flows used in financing activities were $338 million, $160 million and $367 million, respectively.

Joint Credit Facilities and Short-Term Debt

The Company’s financial policy precludes issuing commercial paper in excess of its supporting lines of credit. Dominion, Consolidated Natural Gas Company (CNG), a wholly-owned subsidiary of Dominion, and the Company have two three-year revolving joint credit facilities that allow aggregate borrowings of up to $2.25 billion. The Company is required to pay minimal annual commitment fees to maintain the joint credit facilities. The facilities include a $1.5 billion credit facility that was entered into in May 2004 and terminates in May 2007 and a $750 million credit facility that was entered into in May 2002 and terminates in May 2005. It is expected that the $750 million credit facility will be renewed prior to its maturity. These credit facilities are being used for working capital, as support for the combined commercial paper programs of Dominion, CNG and the Company, and the issuance of

2004 / Page 19

letters of credit of up to $500 million under the $1.5 billion credit facility and $200 million under the $750 million credit facility. At December 31, 2004, capacity available under the two credit facilities was $1.5 billion.

Both joint credit agreements contain various terms and conditions that could affect the Company’s ability to borrow funds under these facilities, accelerate repayment of any outstanding Company borrowings or possibly result in the termination of the commitment to lend funds to the Company. These terms and conditions include maximum debt to total capital ratios, cross-default provisions and material adverse change clauses. Although the joint credit agreements contain material adverse change clauses, the participating lenders, under those specific provisions, cannot refuse to advance funds to the Company for the repurchase of its outstanding commercial paper.

The ratio of the Company’s debt to total capital, as defined by the agreements, should not exceed 60% at the end of any fiscal quarter. As of December 31, 2004, the Company’s calculated debt to total capital ratio was 50%. Under the agreements’ cross-default provisions, if the Company or any of its material subsidiaries fail to make payment on various debt obligations in excess of $25 million, the lenders could require the Company to accelerate its repayment of any outstanding borrowings under the credit facility and the lenders could terminate their commitment to lend funds to the Company. However, any defaults on indebtedness by Dominion, CNG or any material subsidiaries of those affiliates would not affect the lenders’ commitment to the Company under the joint credit agreements.

At December 31, 2004, total outstanding commercial paper supported by the joint credit facilities was $573 million, of which a total of $267 million was the Company’s borrowings, with a weighted average interest rate of 2.35%. Commercial paper borrowings are used primarily to fund working capital requirements, as a bridge to long-term debt financing and may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash provided by operations.

At December 31, 2004, total outstanding letters of credit supported by the joint credit facilities were $183 million, of which a total of $104 million was issued on behalf of an unregulated subsidiary of the Company.

Long-Term Debt

In August 2004, in connection with the acquisition of a generating facility, the Company assumed $109 million of private placement bonds and $25 million of pollution control bonds. In November 2004, the Company exchanged $106 million of its 2004 Series A 7.25% senior notes due 2017 (the senior notes) for the outstanding private placement bonds, following the scheduled principal payment of $3 million. The senior notes have the same financial terms as the private placement bonds, but are registered securities. In addition, in November 2004, the Company assumed $79 million of industrial development bonds issued by Pittsylvania County, VA as part of the acquisition of another non-utility generating facility.

In 2004, the Company repaid $250 million of its 8% mortgage bonds due March 1, 2004 and $75 million of its 7.2% senior notes due November 1, 2004.

Common Stock

In 2004, the Company issued 20,115 shares of its common stock to Dominion for cash consideration of $500 million. The Company used the proceeds in part to pay down its $345 million affiliated short-term demand note from Dominion.

In 2004 and 2003, the Company recorded $11 million and $21 million, respectively, of additional paid-in capital in connection with the reduction in amounts payable to Dominion.

Borrowings from Parent

At December 31, 2004, an unregulated subsidiary of the Company had borrowed funds from Dominion totaling $645 million under a short-term demand note. At December 31, 2004, the Company had outstanding borrowings from Dominion of $220 million under a long-term note. Interest charges incurred by the Company related to these borrowings were $11 million in 2004. Interest charges incurred in 2003 were not material.

Amounts Available under Shelf Registrations

At February 1, 2005, the Company had approximately $670 million of available capacity under currently effective shelf registrations. The shelf registrations would permit the Company to issue debt and preferred securities to meet future capital requirements.

Credit Ratings

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. Management believes that the current credit ratings of the Company provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to the Company may affect the Company’s ability to access these funding sources or cause an increase in the return required by investors.

Both quantitative (financial strength) and qualitative (business or operating characteristics) factors are considered by the credit rating agencies in establishing the Company’s credit ratings. Credit ratings should be evaluated independently and are subject to revision or withdrawal at any time by the assigning rating organization. The credit ratings for the Company are most affected by the Company’s financial profile, mix of regulated and non-regulated businesses and respective cash flows, changes in methodologies used by the rating agencies and “event risk,” if applicable.

Credit ratings for the Company as of February 1, 2005 follow:

	Standard & Poor’s	Moody’s
Mortgage bonds	A-	A2
Senior unsecured (including tax-exempt) debt securities	BBB+	A3
Preferred securities of affiliated trust	BBB-	Baa1
Preferred stock	BBB-	Baa2
Commercial paper	A-2	P-1

2004 / Page 20

As of February 1, 2005, Standard & Poor’s maintains a negative outlook for its ratings of the Company.

Generally, a downgrade in the Company’s credit rating would not restrict its ability to raise short-term or long-term financing so long as its credit rating remains “investment grade,” but it would increase the cost of borrowing. The Company works closely with both Standard & Poor’s and Moody’s with the objective of maintaining the Company’s current credit ratings. As discussed in Risk Factors and Cautionary Statements That May Affect Future Results, in order to maintain its current ratings, the Company may find it necessary to modify its business plans and such changes may adversely affect its growth.

Debt Covenants

As part of borrowing funds and issuing debt (both short-term and long-term) or preferred securities, the Company must enter into enabling agreements. These agreements contain covenants that, in the event of default, could result in the acceleration of principal and interest payments; restrictions on distributions related to its capital stock to Dominion, including dividends, redemptions, repurchases, liquidation payments or guarantee payments; and, in some cases, the termination of credit commitments unless a waiver of such requirements is agreed to by the lenders/security holders. These provisions are customary, with each agreement specifying which covenants apply. These provisions are not necessarily unique to the Company. Some of the typical covenants include:

• The timely payment of principal and interest;

• Information requirements, including submitting financial reports filed with the Securities and Exchange Commission to lenders;

• Performance obligations, audits/inspections, continuation of the basic nature of business, restrictions on certain matters related to merger or consolidation, restrictions on disposition of substantial assets;

• Compliance with collateral minimums or requirements related to mortgage bonds; and

• Limitations on liens.

The Company monitors the covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2004, there were no events of default under the Company’s covenants.

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

Contractual Obligations

The Company is party to numerous contracts and arrangements obligating the Company to make cash payments in future years. These contracts include financing arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services and financial derivatives. Presented below is a table summarizing cash payments that may result from contracts to which the Company is a party as of December 31, 2004. For purchase obligations and other liabilities, amounts are based upon contract terms, including fixed and minimum quantities to be purchased at fixed or market-based prices. Actual cash payments will be based upon actual quantities purchased and prices paid and will likely differ from amounts presented below. The table excludes all amounts classified as current liabilities on the Consolidated Balance Sheets, other than current maturities of long-term debt and interest payable. The majority of current liabilities will be paid in cash in 2005.

	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
(millions)
Long-term debt(1)	$	12	$	1,876	$	408	$	2,666	$	4,962
Interest payments(2)		265		484		324		2,289		3,362
Leases		36		45		26		29		136
Purchase obligations(3):
Purchased electric capacity for utility operations		509		968		858		3,103		5,438
Fuel used for utility operations		691		673		245		51		1,660
Energy commodity purchases for resale(4)		422		21		2		—		445
Other		28		6		—		—		34
Other long-term liabilities(5)
Financial derivative—commodities(4)		233		39		—		—		272
Other contractual obligations		1		11		2		—		14
Total cash payments	$	2,197	$	4,123	$	1,865	$	8,138	$	16,323

(1) Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders.

(2) Does not reflect the Company’s ability to defer distributions related to its junior subordinated notes payable to affiliated trust.

(3) Amounts exclude open purchase orders for services that are provided on demand, the timing of which cannot be determined.

(4) Represents the summation of settlement amounts, by contracts, due from the Company if all physical or financial transactions among the Company and its counterparties were liquidated and terminated.

(5) Excludes regulatory liabilities, AROs and employee benefit plan obligations that are not contractually fixed as to timing and amount. See Notes 11, 12 and 18 to the Consolidated Financial Statements. Deferred income taxes are also excluded since cash payments are based primarily on taxable income for each discrete fiscal year.

Planned Capital Expenditures

The Company’s planned capital expenditures during 2005 are expected to total approximately $870 million, which includes the cost of acquiring certain non-utility generating facilities. In February 2005, the Company completed the termination of a long-term power purchase agreement and acquisition of the related generating facility used by Panda-Rosemary LP, a non-utility generator, to provide electricity to the Company. See Restructuring of Contract with Non-Utility Generator under Future Issues and Other Matters. For 2006, planned capital expenditures are expected to be approximately $900 million. Included in the Company’s total planned capital expenditures are the following:

Capacity

Based on available generation capacity and current estimates of growth in customer demand, the Company will likely need additional baseload generation in the future. However, the Company currently has no definite plans to build any new baseload generating units in the near-term. As part of the Company’s ongoing generation supply strategy, the Company continues to

2004 / Page 21

evaluate the development of new baseload plants to meet customer demand for additional generation needs in the future. Through 2007, the Company will continue to meet any additional capacity and energy requirements through market purchases.

Plant and Equipment

The Company’s annual capital expenditures for plant and equipment for 2005, including environmental upgrades and construction improvements, are expected to total approximately as follows:

• Generation and nuclear fuel: $400 million includes the cost of acquiring certain non-utility generating facilities;

• Transmission: $120 million; and

• Distribution: $350 million primarily provides for customer growth, reliability initiatives and routine replacements.

Future Issues and Other Matters

Status of Deregulation in Virginia

The Virginia Electric Utility Restructuring Act (Virginia Restructuring Act) was enacted in 1999 and established a plan to restructure the electric utility industry in Virginia. The Virginia Restructuring Act addressed among other things: capped base rates, regional transmission organization (RTO) participation, retail choice, the recovery of stranded costs and the functional separation of a utility’s electric generation from its electric transmission and distribution operations.

Retail choice has been available to all of the Company’s Virginia regulated electric customers since January 1, 2003. The Company has also separated its generation, distribution and transmission functions through the creation of divisions. Virginia codes of conduct ensure that Virginia Power’s generation and other divisions operate independently and prevent cross-subsidies between the generation and other divisions.

Since the passage of the Virginia Restructuring Act, the competitive environment has not developed in Virginia as anticipated. In April 2004, the Governor of Virginia signed into law amendments to the Virginia Restructuring Act and the Virginia fuel factor statute. The amendments extend capped base rates to December 31, 2010, unless modified or terminated earlier under the Virginia Restructuring Act. In addition to extending capped rates, the amendments:

• Lock in the Company’s fuel factor provisions until the earlier of July 1, 2007 or the termination of capped rates;

• Provide for a one-time adjustment of the Company’s fuel factor, effective July 1, 2007 through December 31, 2010 (unless capped rates are terminated earlier under the Virginia Restructuring Act), with no adjustment for previously incurred over-recovery or under-recovery, thus eliminating deferred fuel accounting for the Virginia jurisdiction; and

• End wires charges on the earlier of July 1, 2007 or the termination of capped rates, consistent with the Virginia Restructuring Act’s original timetable.

The risk of fuel factor-related cost recovery shortfalls may also adversely impact the Company’s cost structure during the transition period, and the Company could realize the negative economic impact of any such adverse event. Conversely, the Company may experience a positive economic impact to the extent that it can reduce its fuel factor-related costs for its electric utility generation-related operations.

Other amendments to the Virginia Restructuring Act were also enacted with respect to a minimum stay exemption program, a wires charges exemption program and allowing the development of a coal-fired generating plant in southwest Virginia for serving default service needs. Under the minimum stay exemption program, large customers with a load of 500 kW or greater would be exempt from the twelve-month minimum stay obligation under capped rates if they return to supply service from the incumbent utility at market-based pricing after they have switched to supply service with a competitive service provider. The wires charge exemption program would allow large industrial and commercial customers, as well as aggregated customers in all rate classes, to avoid paying wires charges by agreeing to market-based pricing upon return to the incumbent electric utility. In January 2005, the Company filed compliance plans for both of these programs.

RTO

In September 2002, the Company and PJM Interconnection, LLC (PJM) entered into an agreement that provides for, subject to regulatory approval and certain provisions, the Company to become a member of PJM, transfer functional control of its electric transmission facilities to PJM for inclusion in a new PJM South Region and integrate its control area into the PJM energy markets. The agreement also allocates costs of implementation of the agreement among the parties.

        In October 2004, the FERC issued an order conditionally approving the Company’s application to join PJM. In its order, FERC determined that: (i) the Company’s proposed transmission rate treatment must conform to a regional transmission rate design, and (ii) the Company must assess all available evidence and determine whether the requested deferral of expenditures related to the establishment and operation of an RTO should be recorded as a regulatory asset until the end of the Virginia retail rate cap period. In a separate order issued in September 2004, FERC granted authority to the Company and its affiliates with market based rate authority to charge market based rates for sales of electric energy and capacity to loads located within the Company’s service territory upon its integration into PJM.

The Company has made filings with both the Virginia Commission and North Carolina Utilities Commission (North Carolina Commission) requesting authorization to become a member of PJM. In October 2004, the Company filed a settlement agreement with the Virginia Commission resolving most of the issues raised by interested parties in the proceeding, and hearings were held to address the remaining issues. The Virginia Commission approved the Company’s application to join PJM in November 2004 subject to the terms and conditions of the settlement agreement. The North Carolina Commission evidentiary hearing was held in January 2005. The Company cannot predict the outcome of this matter at this time.

2004 / Page 22

North Carolina Rate Matter

In connection with the North Carolina Commission’s approval of the CNG acquisition, the Company agreed not to request an increase in North Carolina retail electric base rates before 2006, except for certain events that would have a significant financial impact on the Company’s utility operations. Fuel rates are still subject to change under the annual fuel cost adjustment proceedings. However, in April 2004, the North Carolina Commission commenced an investigation into the Company’s North Carolina base rates and subsequently ordered the Company to file a general rate case to show cause why its North Carolina base rates should not be reduced. The rate case was filed in September 2004, and in February 2005, the Company reached a tentative settlement with parties in the case that is subject to North Carolina Commission approval before becoming effective.

Recovery of Stranded Costs

Stranded costs are those generation-related costs incurred or commitments made by utilities under cost-based regulation that may not reasonably be expected to be recovered in a competitive market. At December 31, 2004, the Company’s exposure to potentially stranded costs included long-term power purchase contracts that could ultimately be determined to be above market; generating plants that could possibly become uneconomical in a deregulated environment; and unfunded obligations for nuclear plant decommissioning and postretirement benefits not yet recognized in the financial statements. The Company believes capped electric retail rates and, where applicable, wires charges will provide an opportunity to recover a portion of its potentially stranded costs, depending on market prices of electricity and other factors. Recovery of the Company’s potentially stranded costs remains subject to numerous risks even in the capped-rate environment. These include, among others, exposure to long-term power purchase commitment losses, future environmental compliance requirements, changes in tax laws, nuclear decommissioning costs, inflation, increased capital costs and recovery of certain other items.

The enactment of deregulation legislation in 1999 not only caused the discontinuance of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation for the Company’s Virginia jurisdictional utility generation-related operations but also caused the Company to review its utility generation assets for impairment and long-term power purchase agreements for potential losses at that time. Significant assumptions considered in that review included possible future market prices for fuel and electricity, load growth, generating unit availability and future capacity additions in the Company’s market, capital expenditures, including those related to environmental improvements, and decommissioning activities. Based on those analyses, no recognition of plant impairments or contract losses was appropriate at that time. In response to future events resulting from the development of a competitive market structure in Virginia and the expiration or termination of capped rates and wires charges, the Company may have to reevaluate its utility generation assets for impairment and long-term power purchase agreements for potential losses. Assumptions about future market prices for electricity represent a critical factor that affects the results of such evaluations. Since 1999, market prices for electricity have fluctuated significantly and will continue to be subject to volatility. Any such review in the future, which would be highly dependent on assumptions considered appropriate at the time, could possibly result in the recognition of plant impairment or contract losses that would be material to the Company’s results of operations or its financial position.

Changes to Cost Structure—In April 2004, the Governor of Virginia signed into law amendments to the Virginia Restructuring Act and the Virginia fuel factor statute. The amendments extend capped base rates until December 31, 2010, unless capped rates are terminated earlier under the Virginia Restructuring Act. The generation-related cash flows provided by the Virginia Restructuring Act are intended to compensate the Company for continuing to provide generation services and to allow the Company to incur costs to restructure such operations during the transition period. As a result, during the transition period, the Company’s earnings may increase to the extent that it can reduce operating costs for its utility generation-related operations. Conversely, the same risks affecting the recovery of the Company’s stranded costs, discussed above, may also adversely impact its cost structure during the transition period. Accordingly, the Company could realize the negative economic impact of any such adverse event. In addition to managing the cost of its generation-related operations, the Company may also seek opportunities to sell available electric energy and capacity to customers beyond its electric utility service territory. Using cash flows from operations during the transition period, the Company may further alter its cost structure or choose to make additional investments in its business.

The capped rates were derived from rates established as part of the 1998 Virginia rate settlement and do not provide for specific recovery of particular generation-related expenditures, except for certain regulatory assets. To the extent that the Company manages its operations to reduce its overall operating costs below those levels included in the capped rates, the Company’s earnings may increase. Since the enactment of the Virginia Restructuring Act, the Company has been reviewing its cost structure to identify opportunities to reduce the annual operating expenses of its generation-related operations. In the period 2001 through 2004, the Company negotiated the termination of several long-term power purchase agreements that is expected to reduce capacity payments in 2005 by $179 million.

Environmental Matters

The Company is subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in

2004 / Page 23

increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. Historically, the Company recovered such costs arising from regulated electric operations through utility rates. However, to the extent that environmental costs are incurred in connection with operations regulated by the Virginia Commission, during the period ending December 31, 2010, in excess of the level currently included in the Virginia jurisdictional electric retail rates, the Company’s results of operations will decrease. After that date, recovery through regulated rates may be sought for only those environmental costs related to regulated electric transmission and distribution operations and recovery, if any, through the generation component of rates will be dependent upon the market price of electricity.

Environmental Protection and Monitoring Expenditures

The Company incurred approximately $115 million, $100 million and $117 million of expenses (including depreciation) during 2004, 2003 and 2002, respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $124 million in 2005 and $136 million in 2006. In addition, capital expenditures related to environmental controls were $84 million, $197 million and $214 million for 2004, 2003 and 2002, respectively. These expenditures are expected to be approximately $28 million for 2005 and $126 million for 2006.

Clean Air Act Compliance

The Clean Air Act requires the Company to reduce its emissions of sulfur dioxide (SO₂) and nitrogen oxide (NO_X), which are gaseous by-products of fossil fuel combustion. The Clean Air Act’s SO₂ and NO_X reduction programs include:

• The issuance of a limited number of SO₂ emission allowances. Each allowance permits the emission of one ton of SO₂ into the atmosphere. The allowances may be transacted with a third party; and

• NO_X emission limitations applicable during the ozone season months from May through September and on an annual average basis.

Implementation of projects to comply with SO₂ and NO_X limitations are ongoing and will be influenced by changes in the regulatory environment, availability of allowances, various state and federal control programs and emission control technology. In response to these requirements, the Company estimates it will make capital expenditures at its affected generating facilities of approximately $455 million during the period 2005 through 2009 for SO₂ and NO_x emission control equipment.

Other EPA Matters

In relation to a Notice of Violation received by the Company in 2000 from the Environmental Protection Agency (EPA), the Company entered into a Consent Decree settlement in 2003 and committed to improve air quality. The Company has already incurred certain capital expenditures for environmental improvements at its coal-fired stations in Virginia and West Virginia. The Company continues to commit to additional measures in its current financial plans and capital budget to satisfy the requirements of the Consent Decree.

Future Environmental Regulations

In January 2004, the EPA proposed additional regulations addressing pollution transport from electric generating units as well as the regulation of mercury and nickel emissions. These regulatory actions, in addition to revised regulations to address regional haze, are expected to be finalized in 2005 and could require additional reductions in emissions from the Company’s fossil fuel-fired generating facilities. If these new emission reduction requirements are imposed, significant additional expenditures may be required.

The U.S. Congress is considering various legislative proposals that would require generating facilities to comply with more stringent air emissions standards. Emission reduction requirements under consideration would be phased in under a variety of periods of up to 15 years. If these new proposals are adopted, additional significant expenditures may be required.

In 1997, the United States signed an international Protocol to limit man-made greenhouse emissions under the United Nations Framework Convention on Climate Change. However, the Protocol will not become binding unless approved by the U.S. Senate. Currently, the Bush Administration has indicated that it will not pursue ratification of the Protocol and has set a voluntary goal of reducing the nation’s greenhouse gas emission intensity by 18% over the next 10 years. Several legislative proposals that include provisions seeking to impose mandatory reductions of greenhouse gas emissions are under consideration in the United States Congress. The cost of compliance with the Protocol or other mandatory greenhouse gas reduction obligations could be significant. Given the highly uncertain outcome and timing of future action, if any, by the U.S. federal government on this issue, the Company cannot predict the financial impact of future climate change actions on its operations at this time.

Nuclear Insurance

The Price-Anderson Act expired in August 2002, but operating nuclear reactors continue to be covered by the law, which would channel and cap claims if a nuclear accident should occur. The Price-Anderson Act was first enacted in 1957 and has been renewed three times since 1967. Congress is currently holding hearings to reauthorize the legislation.

Other Matters

Restructuring of Contract with Non-Utility Generator

In February 2005, the Company paid $42 million in cash and assumed $62 million of debt in connection with the termination of a long-term power purchase agreement and acquisition of the related generating facility used by Panda-Rosemary LP, a non-utility generator, to provide electricity to the Company. The transaction is part of an ongoing program that seeks to achieve competitive cost structures of the Company’s utility generation business and is expected to reduce annual capacity payments by $18 million. The purchase price for the acquisition was allocated to the assets and liabilities acquired based on their estimated fair values as of the date of acquisition. In connection with the termination of the agreement, the Company expects to record an after-tax charge of approximately $46 million.

2004 / Page 24

Long-Term Power Tolling Contract

In the fourth quarter of 2004, the Company recorded a $112 million after-tax charge related to its interest in a long-term power tolling contract with a 551 megawatt combined cycle facility located in Batesville, Mississippi. The Company decided to divest its interest in the long-term power tolling contract in connection with Dominion’s reconsideration of the scope of certain activities of the Clearinghouse, including those conducted on behalf of the Company’s business segments, and Dominion’s ongoing strategy to focus on business activities within the MAIN to Maine region. The charge is based on the Company’s evaluation of preliminary bids received from third parties, reflecting the expected amount of consideration that would be required by a third party for its assumption of the Company’s interest in the contract in the first quarter of 2005.

Risk Factors and Cautionary Statements That May Affect Future Results

Factors that may cause actual results to differ materially from those indicated in any forward-looking statement include weather conditions; governmental regulations; cost of environmental compliance; inherent risk in the operation of nuclear facilities; fluctuations in energy-related commodities prices and the effect these could have on the Company’s earnings, liquidity position and the underlying value of its assets; trading counterparty credit risk; capital market conditions, including price risk due to marketable securities held as investments in trusts and benefit plans; fluctuations in interest rates; changes in rating agency requirements or ratings; changes in accounting standards; collective bargaining agreements and labor negotiations; the risks of operating businesses in regulated industries that are subject to changing regulatory structures; changes to regulated electric rates recovered by the Company; the transfer of control over electric transmission facilities to a regional transmission organization; and political and economic conditions (including inflation and deflation). Other more specific risk factors are as follows:

The Company’s operations are weather sensitive. The Company’s results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for electricity and affect the price of energy commodities. In addition, severe weather, including hurricanes, winter storms and droughts, can be destructive, causing outages and property damage that require the Company to incur additional expenses.

The Company is subject to complex government regulation that could adversely affect its operations. The Company’s operations are subject to extensive federal, state and local regulation and may require numerous permits, approvals and certificates from various governmental agencies. The Company must also comply with environmental legislation and associated regulations. Management believes the necessary approvals have been obtained for the Company’s existing operations and that its business is conducted in accordance with applicable laws. However, new laws or regulations, or the revision or reinterpretation of existing laws or regulations, may require the Company to incur additional expenses.

Costs of environmental compliance, liabilities and litigation could exceed the Company’s estimates which could adversely affect its results of operations. Compliance with federal, state and local environmental laws and regulations may result in increased capital, operating and other costs, including remediation and containment expenses and monitoring obligations. In addition, the Company may be a responsible party for environmental clean-up at a site identified by a regulatory body. Management cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean-up and compliance costs, and the possibility that changes will be made to the current environmental laws and regulations. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.

The Company is exposed to cost-recovery shortfalls because of capped base rates and amendments to the fuel factor statute in effect in Virginia. Under the Virginia Restructuring Act, as amended in April 2004, the Company’s base rates (excluding, generally, a fuel factor with limited adjustment provisions, and certain other allowable adjustments) remain unchanged until December 31, 2010 unless modified or terminated consistent with the Virginia Restructuring Act. Although the Virginia Restructuring Act allows for the recovery of certain generation-related costs during the capped rates period, the Company remains exposed to numerous risks of cost-recovery shortfalls. These include exposure to potentially stranded costs, future environmental compliance requirements, tax law changes, costs related to hurricanes or other weather events, inflation, the cost of obtaining replacement power during unplanned plant outages and increased capital costs. In addition, under the 2004 amendments to the Virginia fuel factor statute, the Company’s current Virginia fuel factor provisions are locked-in until the earlier of July 1, 2007 or the termination of capped rates by order of the Virginia Commission.

The amendments provide for a one-time adjustment of the Company’s fuel factor, effective July 1, 2007 through December 31, 2010, with no adjustment for previously incurred over-recovery or under-recovery, thus eliminating deferred fuel accounting. As a result of the locked-in fuel factor and the uncertainty of what the one-time adjustment will be, the Company is exposed to fuel price risk. This risk includes exposure to increased costs of fuel, including the energy portion of certain purchased power costs.

Under the Virginia Restructuring Act, the generation portion of the Company’s electric utility operations is open to competition and resulting uncertainty. Under the Virginia Restructuring Act, the generation portion of the Company’s electric utility operations in Virginia is open to competition and is no longer subject to cost-based regulation. To date, the competitive market has been slow to develop. Consequently, it is difficult to predict the pace at which the competitive environment will evolve and the extent to which the Company will face increased competition and be able to operate profitably within this competitive environment.

2004 / Page 25

There are inherent risks in the operation of nuclear facilities. The Company operates nuclear facilities that are subject to inherent risks. These include the threat of terrorist attack and ability to dispose of spent nuclear fuel, the disposal of which is subject to complex federal and state regulatory constraints. These risks also include the cost of and the Company’s ability to maintain adequate reserves for decommissioning, costs of plant maintenance and exposure to potential liabilities arising out of the operation of these facilities. The Company maintains decommissioning trusts and external insurance coverage to manage the financial exposure to these risks. However, it is possible that costs arising from claims could exceed the amount of any insurance coverage.

The use of derivative instruments could result in financial losses and liquidity constraints. The Company uses derivative instruments, including futures, forwards, options and swaps, to manage its commodity and financial market risks. In addition, the Company purchases and sells commodity- based contracts in the natural gas, electricity and oil markets for trading purposes. In the future, the Company could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these contracts involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

For additional information concerning derivatives and commodity-based trading contracts, see Market Rate Sensitive Instruments and Risk Management in Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Notes 2 and 7 to the Consolidated Financial Statements.

The Company is exposed to market risks beyond its control in its energy clearinghouse operations which could adversely affect its results of operations and future growth. The Company’s energy clearinghouse and risk management operations are subject to multiple market risks including market liquidity, counterparty credit strength and price volatility. Many industry participants have experienced severe business downturns resulting in some companies exiting or curtailing their participation in the energy trading markets. This has led to a reduction in the number of trading partners and lower industry trading revenues. Declining creditworthiness of some of the Company’s trading counterparties may limit the level of its trading activities with these parties and increase the risk that these parties may not perform under a contract.

An inability to access financial markets could affect the execution of the Company’s business plan. The Company relies on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flows from its operations. Management believes that the Company will maintain sufficient access to these financial markets based upon current credit ratings. However, certain disruptions outside of the Company’s control may increase its cost of borrowing or restrict its ability to access one or more financial markets. Such disruptions could include an economic downturn, the bankruptcy of an unrelated energy company or changes to the Company’s credit ratings. Restrictions on the Company’s ability to access financial markets may affect its ability to execute its business plan as scheduled.

Changing rating agency requirements could negatively affect the Company’s growth and business strategy. As of February 1, 2005, the Company’s senior secured debt is rated A-, negative outlook, by Standard & Poor’s and A2, stable outlook, by Moody’s. Both agencies have implemented more stringent applications of the financial requirements for various ratings levels. In order to maintain its current credit ratings in light of these or future new requirements, the Company may find it necessary to take steps or change its business plans in ways that may adversely affect its growth and earnings. A reduction in the Company’s credit ratings by either Standard & Poor’s or Moody’s could increase its borrowing costs, adversely affect operating results, and could require it to post additional margin in connection with some of its trading and marketing activities.

Potential changes in accounting practices may adversely affect the Company’s financial results. The Company cannot predict the impact that future changes in accounting standards or practices may have on public companies in general, the energy industry or its operations specifically. New accounting standards could be issued that could change the way the Company records revenues, expenses, assets and liabilities. These changes in accounting standards could adversely affect the Company’s reported earnings or could increase reported liabilities.

Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse effect on the operations of the Company. Implementation of the Company’s growth strategy is dependent on its ability to recruit, retain and motivate employees. Competition for skilled employees in some areas is high and the inability to retain and attract these employees could adversely affect the Company’s business and future financial condition.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs under Part II, Item 7. MD&A of this Form 10-K. The reader’s attention is directed to those paragraphs and Risk Factors and Cautionary Statements That May Affect Future Results in MD&A, for discussion of various risks and uncertainties that may affect the future of the Company.

Market Rate Sensitive Instruments and Risk Management

The Company’s financial instruments, commodity contracts and related derivative instruments are exposed to potential losses due to adverse changes in interest rates, foreign currency exchange

2004 / Page 26

rates, commodity prices and equity security prices, as described below. Interest rate risk generally is related to the Company’s outstanding debt. Commodity price risk is present in the Company’s electric operations and energy marketing and trading operations due to the exposure to market shifts for prices received and paid for natural gas, electricity and other commodities. The Company uses derivative instruments to manage price risk exposures for these operations. The Company is exposed to equity price risk through various portfolios of equity securities.

The following sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% unfavorable change in commodity prices, interest rates and foreign currency exchange rates.

Commodity Price Risk

Trading Activities

As part of its strategy to market energy and to manage related risks, the Company manages a portfolio of commodity-based derivative instruments held for trading purposes. These contracts are sensitive to changes in the prices of natural gas, electricity and certain other commodities. The Company uses established policies and procedures to manage the risks associated with these price fluctuations and uses derivative instruments, such as futures, forwards, swaps and options, to mitigate risk by creating offsetting market positions. A hypothetical 10% unfavorable change in commodity prices would have resulted in a decrease of approximately $104 million and $100 million in the fair value of its commodity-based financial derivatives held for trading purposes as of December 31, 2004 and 2003, respectively.

The impact of a change in energy commodity prices on the Company’s trading derivative commodity instruments at a point in time is not necessarily representative of the results that will be realized when such contracts are ultimately settled.

Non-Trading Activities

The Company manages the price risk associated with purchases and sales of natural gas and electricity by using derivative commodity instruments including futures, forwards, options and swaps. For sensitivity analysis purposes, the fair value of the Company’s non-trading derivative commodity instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Market prices and volatility are principally determined based on quoted prices on the futures exchange. A hypothetical 10% unfavorable change in market prices of the Company’s non-trading commodity-based financial derivative instruments would have resulted in a decrease in fair value of approximately $12 million and $6 million as of December 31, 2004 and 2003, respectively.

The impact of a change in energy commodity prices on the Company’s non-trading commodity based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when such contracts are ultimately settled. Net losses from derivative commodity instruments used for hedging purposes, to the extent realized, are substantially offset by recognition of the hedged transaction, such as revenue from sales.

Interest Rate Risk

The Company manages its interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. The Company also enters into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For financial instruments outstanding at December 31, 2004, a hypothetical 10% increase in market interest rates would decrease annual earnings by approximately $3 million. A hypothetical 10% increase in market interest rates, as determined at December 31, 2003, would have resulted in a decrease in annual earnings of approximately $2 million.

Foreign Currency Exchange Risk

The Company manages its foreign exchange risk exposure associated with anticipated future purchases of nuclear fuel processing services denominated in foreign currencies by utilizing currency forward contracts. As a result of holding these contracts as hedges, the Company’s exposure to foreign currency risk for these purchases is minimal. A hypothetical 10% unfavorable change in relevant foreign exchange rates would have resulted in a decrease of approximately $10 million and $15 million in the fair value of currency forward contracts held by the Company at December 31, 2004 and 2003, respectively.

Investment Price Risk

The Company is subject to investment price risk due to marketable securities held as investments in nuclear decommissioning trust funds. In accordance with current accounting standards, these marketable securities are reported on the Consolidated Balance Sheets at fair value. The Company recognized net realized gains (net of investment income) on nuclear decommissioning trust investments of $24 million for 2004 and $36 million for 2003. The Company recorded, in AOCI, net unrealized gains on decommissioning trust investments of $49 million for 2004 and net unrealized gains of $100 million for 2003.

Dominion sponsors employee pension and other postretirement benefit plans, in which the Company’s employees participate, that hold investments in trusts to fund benefit payments. To the extent that the values of investments held in these trusts decline, the effect will be reflected in the Company’s recognition of the periodic cost of such employee benefit plans and the determination of the amount of cash to be contributed by the Company to the employee benefit plans.

Risk Management Policies

The Company has operating procedures in place that are administered by experienced management to help ensure that proper internal controls are maintained. In addition, Dominion has established an independent function at the corporate level to monitor compliance with the risk management policies of all subsidiaries, including the Company. Dominion maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion also monitors the financial condition of existing counterparties on an ongoing basis. Based on Dominion’s credit policies and the Company’s December 31, 2004 provision for credit losses, management believes that it is unlikely that a material adverse effect on the Company’s financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

2004 / Page 27

Item 8. Financial Statements and Supplementary Data

Index

	Page No.
Report of Management’s Responsibilities	29
Report of Independent Registered Public Accounting Firm	30
Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002	31
Consolidated Balance Sheets at December 31, 2004 and 2003	32
Consolidated Statements of Common Shareholder’s Equity and Comprehensive Income at December 31, 2004, 2003 and 2002 and for the years then ended	34
Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002	35
Notes to Consolidated Financial Statements	36

2004 / Page 28

Report of Management’s Responsibilities

Because the Company is not an accelerated filer as defined in Exchange Act Rule 12b-2, it is not required to comply with Securities and Exchange Commission rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 until December 31, 2005.

The Company’s management is responsible for all information and representations contained in the Consolidated Financial Statements and other sections of the Company’s annual report on Form 10-K. The Consolidated Financial Statements, which include amounts based on estimates and judgments of management, have been prepared in conformity with accounting principles generally accepted in the United States of America. Other financial information in the Form 10-K is consistent with that in the Consolidated Financial Statements.

Management maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that the Company’s assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. Management recognizes the inherent limitations of any system of internal control and, therefore, cannot provide absolute assurance that the objectives of the established internal controls will be met. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits. Management believes that during 2004 the system of internal control was adequate to accomplish the intended objectives.

The Consolidated Financial Statements have been audited by Deloitte & Touche LLP, independent registered public accounting firm, who have been engaged by Dominion’s Audit Committee, which is comprised entirely of independent directors. Deloitte & Touche LLP’s audit was conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States).

The Board of Directors also serves as the Company’s Audit Committee and meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss auditing, internal accounting control and financial reporting matters of the Company and to ensure that each is properly discharging its responsibilities.

Management recognizes its responsibility for fostering a strong ethical climate so that the Company’s affairs are conducted according to the highest standards of personal corporate conduct. This responsibility is characterized and reflected in the Company’s code of ethics, which addresses potential conflicts of interest, compliance with all domestic and foreign laws, the confidentiality of proprietary information and full disclosure of public information.

2004 / Page 29

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Virginia Electric and Power Company

Richmond, Virginia

We have audited the accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of income, common shareholder’s equity and comprehensive income, and of cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Virginia Electric and Power Company and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the consolidated financial statements, in 2003 the Company changed its methods of accounting to adopt new accounting standards for: asset retirement obligations, contracts involved in energy trading, derivative contracts not held for trading purposes, derivative contracts with a price adjustment feature, the consolidation of variable interest entities, and guarantees.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 28, 2005

2004 / Page 30

Virginia Electric and Power Company

Consolidated Statements of Income

Year Ended December 31,	2004		2003			2002
(millions)
Operating Revenue	$	5,741	$	5,437		$	4,972
Operating Expenses
Electric fuel and energy purchases, net		1,750		1,472			1,281
Purchased electric capacity		550		607			691
Purchased gas		110		115			—
Other purchased energy commodities		518		189			—
Other operations and maintenance—external		1,019		991			626
Other operations and maintenance—affiliated		276		293			267
Depreciation and amortization		496		458			495
Other taxes		169		173			152
Total operating expenses		4,888		4,298			3,512
Income from operations		853		1,139			1,460
Other income		71		81			32
Interest and related charges:
Interest expense—other		223		272			275
Interest expense—junior subordinated notes payable to affiliated trust		31		—			—
Distributions—mandatorily redeemable trust preferred securities		—		30			19
Total interest and related charges		254		302			294
Income before income taxes		670		918			1,198
Income taxes		239		336			425
Income before cumulative effect of changes in accounting principles		431		582			773
Cumulative effect of changes in accounting principles (net of income taxes of $14)		—		(21	)		—
Net Income		431		561			773
Preferred dividends		16		15			16
Balance available for common stock	$	415	$	546		$	757

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

2004 / Page 31

Virginia Electric and Power Company

Consolidated Balance Sheets

December 31,	2004			2003
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	2		$	46
Accounts receivable:
Customers (less allowance for doubtful accounts of $13 in 2004 and $9 in 2003)		1,289			1,149
Other		62			67
Receivables from affiliates		65			81
Inventories (average cost method):
Materials and supplies		184			155
Fossil fuel		174			144
Gas stored		196			197
Derivative assets		1,097			1,096
Prepayments		42			56
Other		196			107
Total current assets		3,307			3,098
Investments
Nuclear decommissioning trust funds		1,119			1,010
Other		22			39
Total investments		1,141			1,049
Property, Plant and Equipment
Property, plant and equipment		19,716			19,129
Accumulated depreciation and amortization		(7,706	)		(7,391	)
Net property, plant and equipment		12,010			11,738
Deferred Charges and Other Assets
Regulatory assets		361			438
Derivative assets		174			227
Other		325			334
Total deferred charges and other assets		860			999
Total assets	$	17,318		$	16,884

2004 / Page 32

Virginia Electric and Power Company

Consolidated Balance Sheets

December 31,	2004		2003
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	12	$	325
Short-term debt		267		717
Accounts payable, trade		799		850
Payables to affiliates		122		138
Affiliated current borrowings		645		154
Accrued interest, payroll and taxes		176		202
Derivative liabilities		1,304		1,123
Other		235		284
Total current liabilities		3,560		3,793
Long-Term Debt
Long-term debt		4,326		4,112
Junior subordinated notes payable to affiliated trust		412		412
Notes payable—other affiliates		220		220
Total long-term debt		4,958		4,744
Deferred Credits and Other Liabilities
Deferred income taxes		2,200		1,964
Deferred investment tax credits		64		80
Asset retirement obligations		781		740
Derivative liabilities		163		393
Regulatory liabilities		387		374
Other		79		126
Total deferred credits and other liabilities		3,674		3,677
Total liabilities		12,192		12,214
Commitments and Contingencies (see Note 19)
Preferred Stock Not Subject to Mandatory Redemption		257		257
Common Shareholder’s Equity
Common stock—no par, 300,000 shares authorized; shares outstanding: 198,047 shares in 2004 and 177,932 shares in 2003		3,388		2,888
Other paid-in capital		50		38
Retained earnings		1,302		1,405
Accumulated other comprehensive income		129		82
Total common shareholder’s equity		4,869		4,413
Total liabilities and shareholder’s equity	$	17,318	$	16,884

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

2004 / Page 33

Virginia Electric and Power Company

Consolidated Statements of Common Shareholder’s Equity and Comprehensive Income

	Common Stock			Other Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
	Shares	Amount
(shares in thousands, all other amounts in millions)
Balance at December 31, 2001	172	$	2,738	$	14	$	1,128		$	(4	)	$	3,876
Comprehensive income:
Net income							773						773
Net deferred gains on derivatives—hedging activities, net of $4 tax expense										7			7
Amount reclassified to net income:
Net losses on derivatives—hedging activities, net of $2 tax benefit										5			5
Total comprehensive income							773			12			785
Issuance of stock to parent	6		150										150
Tax benefit from stock awards and stock options exercised					1								1
Dividends and other adjustments					1		(482	)					(481	)
Balance at December 31, 2002	178		2,888		16		1,419			8			4,331
Comprehensive income:
Net income							561						561
Net deferred gains on derivatives—hedging activities, net of $9 tax expense										11			11
Unrealized gains on nuclear decommissioning trust funds, net of $44 tax expense										68			68
Amount reclassified to net income:
Realized gains on nuclear decommissioning trust funds, net of $5 tax expense										(7	)		(7	)
Net losses on derivatives—hedging activities, net of $1 tax benefit										2			2
Total comprehensive income							561			74			635
Equity contribution by parent					21								21
Tax benefit from stock awards and stock options exercised					1								1
Dividends							(575	)					(575	)
Balance at December 31, 2003	178		2,888		38		1,405			82			4,413
Comprehensive income:
Net income							431						431
Net deferred gains on derivatives—hedging activities, net of $10 tax expense										16			16
Unrealized gains on nuclear decommissioning trust funds, net of $20 tax expense										32			32
Amount reclassified to net income:
Realized gains on nuclear decommissioning trust funds, net of $1 tax expense										(2	)		(2	)
Net losses on derivatives—hedging activities, net of $0.5 tax benefit										1			1
Total comprehensive income							431			47			478
Issuance of stock to parent	20		500										500
Equity contribution by parent					11								11
Tax benefit from stock awards and stock options exercised					1								1
Dividends							(534	)					(534	)
Balance at December 31, 2004	198	$	3,388	$	50	$	1,302		$	129		$	4,869

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

2004 / Page 34

Virginia Electric and Power Company

Consolidated Statements of Cash Flows

Year Ended December 31,	2004			2003			2002
(millions)
Operating Activities
Net income	$	431		$	561		$	773
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		578			531			570
Deferred income taxes and investment tax credits, net		125			245			97
Deferred fuel expenses, net		86			(202	)		(20	)
Other adjustments for non-cash items		(16	)		33			15
Changes in:
Accounts receivable		(135	)		(144	)		(297	)
Affiliated accounts receivable and payable		—			42			(16	)
Inventories		(58	)		(50	)		(75	)
Prepayments		14			(9	)		138
Accounts payable, trade		(51	)		18			205
Accrued interest, payroll and taxes		(15	)		17			(5	)
Other operating assets and liabilities		211			138			(113	)
Net cash provided by operating activities		1,170			1,180			1,272
Investing Activities
Plant construction and other property additions		(761	)		(986	)		(748	)
Nuclear fuel		(96	)		(97	)		(59	)
Purchases of securities		(277	)		(342	)		—
Proceeds from sales of securities		237			256			—
Other		21			63			(50	)
Net cash used in investing activities		(876	)		(1,106	)		(857	)
Financing Activities
Issuance (repayment) of short-term debt, net		(450	)		274			7
Short-term borrowings from parent, net		491			54			100
Issuance of notes payable to parent		—			220			—
Issuance of preferred securities by subsidiary trust		—			—			400
Repayment of preferred securities by subsidiary trust		—			—			(135	)
Issuance of long-term debt and preferred stock		—			1,055			658
Repayment of long-term debt and preferred stock		(344	)		(1,165	)		(887	)
Issuance of common stock		500			—			—
Common stock dividend payments		(518	)		(560	)		(467	)
Preferred stock dividend payments		(16	)		(15	)		(15	)
Other		(1	)		(23	)		(28	)
Net cash used in financing activities		(338	)		(160	)		(367	)
Increase (decrease) in cash and cash equivalents		(44	)		(86	)		48
Cash and cash equivalents at beginning of year		46			132			84
Cash and cash equivalents at end of year	$	2		$	46		$	132
Supplemental Cash Flow Information
Cash paid during the year for:
Interest and related charges, excluding amounts capitalized	$	260		$	260		$	278
Income taxes		46			64			165
Non-cash transactions from financing activities:
Assumption of debt related to the acquisitions of non-utility generating facilities		213			—			—
Non-cash exchange of debt securities		106			—			117
Issuance of common stock in exchange for reduction in amounts payable to parent		—			—			150
Conversion of amounts payable to parent to other paid-in capital		11			21			—

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

2004 / Page 35

Virginia Electric and Power Company

Notes to Consolidated Financial Statements

Note 1. Nature of Operations

Virginia Electric and Power Company (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 an area of approximately 30,000 square-miles in Virginia and northeastern North Carolina. It sells electricity to approximately 2.3 million retail customer accounts, including governmental agencies, and wholesale customers such as rural electric cooperatives, municipalities, power marketers and other utilities. The Virginia service area comprises about 65% of Virginia’s total land area but accounts for over 80% of its population. The Company has trading relationships beyond the geographic limits of its retail service territory and buys and sells natural gas, electricity and other energy-related commodities. Within this document, the “Company” refers to the entirety of Virginia Electric and Power Company, including its Virginia and North Carolina operations and its consolidated subsidiaries.

The Company manages its daily operations through three operating segments: Generation, Energy and Delivery. In addition, the Company reports its corporate and other functions as a segment.

Note 2. Significant Accounting Policies

General

The Company makes certain estimates and assumptions in preparing its Consolidated Financial Statements in accordance with accounting principles generally accepted in the United States of America. 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 revenue and expenses for the periods presented. Actual results may differ from those estimates.

The Consolidated Financial Statements included, after eliminating intercompany transactions and balances, the accounts of the Company and its majority-owned subsidiaries, and those variable interest entities (VIEs) where the Company has been determined to be the primary beneficiary.

Certain amounts in the 2003 and 2002 Consolidated Financial Statements and footnotes have been reclassified to conform to the 2004 presentation.

Operating Revenue

Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. The Company’s customer accounts receivable at December 31, 2004 and 2003 included $251 million and $234 million, respectively, of accrued unbilled revenue based on estimated amounts of electric energy delivered but not yet billed to its utility customers. The Company estimates unbilled utility revenue based on historical usage, applicable customer rates, weather factors and total daily electric generation supplied, after adjusting for estimated losses of energy during transmission.

The primary types of sales and service activities reported as operating revenue include:

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

• Nonregulated electric sales consist primarily of excess generation sold at market-based rates and electric trading revenue;

• Nonregulated gas sales consist primarily of sales of natural gas at market-based rates, brokered gas sales and gas trading revenue; and

• Other revenue consists primarily of sales of coal and also includes miscellaneous service revenue from electric distribution operations, sales of oil and other miscellaneous revenue.

See Derivative Instruments below for a discussion of accounting changes, effective January 1, 2003 and October 1, 2003, which impacted the recognition and classification of changes in fair value, including settlements, of contracts held for energy trading and other purposes.

Electric Fuel and Purchased Energy—Deferred Costs

Where permitted by regulatory authorities, the differences between actual electric fuel and purchased energy expenses and the levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs or recovery of fuel rate revenue in excess of current period expenses is recognized as a regulatory asset or liability.

        Effective January 1, 2004, the Company’s fuel factor provisions for its Virginia retail customers are locked in until the earlier of July 1, 2007 or the termination of capped rates, with a one-time adjustment of the fuel factor, effective July 1, 2007 through December 31, 2010, with no adjustment for previously incurred over-recovery or under-recovery, thus eliminating deferred fuel accounting for the Virginia jurisdiction. As a result, approximately 12% of the cost of fuel used in electric generation and energy purchases used to serve utility customers is subject to deferral accounting. Prior to the amendments to the Virginia Electric Utility Restructuring Act (Virginia Restructuring Act) and the Virginia fuel factor statute in 2004, approximately 93% of the cost of fuel used in electric generation and energy purchases used to serve utility customers had been subject to deferral accounting. Deferred costs associated with the Virginia jurisdictional portion of expenditures incurred through 2003 continue to be reported as regulatory assets, pending recovery through future rates.

2004 / Page 36

Notes to Consolidated Financial Statements, Continued

Income Taxes

The Company files a consolidated federal income tax return and participates in an intercompany tax allocation agreement with Dominion and its subsidiaries. The Company’s current income taxes are based on its taxable income, determined on a separate company basis. At December 31, 2004 and 2003, the Company’s Consolidated Balance Sheets include $24 million of current taxes payable to Dominion (recorded in accrued interest, payroll and taxes) and $4 million of current taxes receivable from Dominion (recorded in prepayments), respectively. However, under the Public Utility Holding Company Act of 1935 (1935 Act) and the intercompany tax allocation agreement, the Company’s cash payments to Dominion are limited. Where permitted by regulatory authorities, the treatment of temporary differences can differ from the requirements of Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes. Accordingly, a regulatory asset has been recognized if it is probable that future revenue will be provided for the payment of deferred tax liabilities. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. Deferred investment tax credits are being amortized over the service lives of the properties giving rise to such credits.

Cash and Cash Equivalents

Current banking arrangements generally do not require checks to be funded until actually presented for payment. At December 31, 2004 and 2003, the Company’s accounts payable includes $41 million and $54 million, respectively of checks outstanding but not yet presented for payment. For purposes of the Consolidated Statements of Cash Flows, the Company considers cash and cash equivalents to include cash on hand, cash in banks and temporary investments purchased with a remaining maturity of three months or less.

Derivative Instruments

The Company uses derivative instruments such as futures, swaps, forwards and options to manage the commodity, currency exchange and financial market risks of its business operations. The Company also manages a portfolio of commodity contracts held for trading purposes as part of its strategy to market energy and to manage related risks.

All derivatives, except those for which an exception applies, are reported on the Consolidated Balance Sheets at fair value. One of the exceptions – normal purchases and normal sales – may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenue resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance. Derivative contracts that are subject to fair value accounting, including unrealized gain positions and purchased options, are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as derivative liabilities. For derivatives that are not designated as hedging instruments, any changes in fair value are recorded in earnings.

Valuation Methods

Fair value is based on actively quoted market prices, if available. In the absence of actively quoted market prices, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, the Company must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis.

For options and contracts with option-like characteristics where pricing information is not available from external sources, the Company generally uses a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. Other option models are used by the Company under special circumstances, including a Spread Approximation Model, when contracts include different commodities or commodity locations and a Swing Option Model, when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts with unique characteristics, the Company estimates fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. If pricing information is not available from external sources, judgment is required to develop the estimates of fair value. For individual contracts, the use of different valuation models or assumptions could have a material effect on the contract’s estimated fair value.

Derivative Instruments Designated as Hedging Instruments

The Company designates derivative instruments, held for purposes other than trading, as fair value or cash flow hedges for accounting purposes. For all derivatives designated as hedges, the relationship between the hedging instrument and the hedged item is formally documented, as well as the risk management objective and strategy for using the hedging instrument. The Company assesses whether the hedge relationship between the derivative and the hedged item is highly effective in offsetting changes in fair value or cash flows both at the inception of the hedge and on an ongoing basis. Any change in fair value of the derivative that is not effective in offsetting changes in the fair value or cash flows of the hedged item is recognized currently in earnings. Also, management may elect to exclude certain gains or losses on hedging instruments from the measurement of hedge effectiveness, such as gains or losses attributable to changes in the time value of options or changes in the difference between spot prices and forward prices, thus requiring that such changes be recorded currently in earnings. The Company discontinues hedge accounting prospectively if a derivative ceases to be highly effective as a hedge.

Cash Flow Hedges—A portion of the Company’s hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of natural gas. The Company also uses foreign currency forward contracts to hedge the variability in foreign exchange rates and interest rate swaps to hedge its exposure to variable interest rates on long-term debt. For cash

2004 / Page 37

Notes to Consolidated Financial Statements, Continued

flow hedge transactions in which the Company is hedging the variability of cash flows, changes in the fair value of the derivative are reported in accumulated other comprehensive income (loss) (AOCI), to the extent effective in offsetting changes in the hedging relationship, until earnings are affected by the hedged item. For cash flow hedge transactions that involve a forecasted transaction, the Company would discontinue hedge accounting if the occurrence of the forecasted transaction was determined to be no longer probable. The Company would reclassify any derivative gains or losses reported in AOCI to earnings when the forecasted item is included in earnings, if it should occur, or earlier, if it becomes probable that the forecasted transaction would not occur.

Fair Value Hedges—The Company also engages in fair value hedges by using derivative instruments to mitigate the fixed price exposure inherent in certain natural gas inventory. In addition, the Company has designated interest rate swaps as fair value hedges to manage its interest rate exposure on certain fixed-rate long-term debt. For fair value hedge transactions, changes in the fair value of the derivative will generally be offset currently in earnings by the recognition of changes in the hedged item’s fair value.

Statement of Income Presentation—Gains and losses on derivatives designated as hedges, when recognized, are included in operating revenue, operating expenses or interest and related charges in the Consolidated Statements of Income. Specific line item classification is determined based on the nature of the risk underlying individual hedge strategies. The portion of gains or losses on hedging instruments determined to be ineffective and the portion of gains or losses on hedging instruments excluded from the measurement of the hedging relationship’s effectiveness, such as gains or losses attributable to changes in the time value of options or changes in the difference between spot prices and forward prices, are included in other operations and maintenance expense.

Derivative Instruments Held for Trading and Other Purposes

As part of its strategy to market energy and to manage related risks, the Company manages a portfolio of commodity-based derivative instruments held for trading purposes, primarily natural gas and electricity. The Company uses established policies and procedures to manage the risks associated with the price fluctuations in these energy commodities and uses various derivative instruments to reduce risk by creating offsetting market positions.

The Company may also hold certain derivative instruments that are not held for trading purposes and are not designated as hedges for accounting purposes. However, to the extent the Company does not hold offsetting positions for such derivatives, management believes these instruments would represent economic hedges that mitigate exposure to fluctuations in commodity prices, interest rates and foreign exchange rates.

Statement of Income Presentation:

• Derivatives Held for Trading Purposes: All changes in fair value, including amounts realized upon settlement, are presented in revenue on a net basis as nonregulated electric sales, non-regulated gas sales and other revenue.

• Financially-Settled Derivatives—Not Held for Trading Purposes or Designated as Hedging Instruments: All unrealized changes in fair value and settlements are presented in other operations and maintenance expense on a net basis.

• Physically-Settled Derivatives—Not Held for Trading Purposes or Designated as Hedging Instruments: Effective October 1, 2003, all statement of income related amounts for physically settled derivative sales contracts are presented in revenue, while all statement of income related amounts for physically settled derivative purchase contracts are reported in expenses. For periods prior to October 1, 2003, unrealized changes in fair value for physically settled derivative contracts were presented in other operations and maintenance expense on a net basis.

Effective January 1, 2003, the Company recognizes revenue or expense from all non-derivative energy-related contracts on a gross basis at the time of contract performance, settlement or termination. Prior to 2003, all energy trading contracts, including non-derivative contracts, were recorded at fair value with changes in fair value reported in revenue on a net basis.

Nuclear Decommissioning Trust Funds

The Company analyzes all securities classified as available-for-sale to determine whether a decline in its fair value should be considered other-than-temporary. The Company uses several criteria to evaluate other-than-temporary declines, including length of time over which the market value has been lower than its cost, the percentage of the decline as compared to its average cost and the expected fair value of the security. If the market value of the security has been less than cost for greater than nine months and the decline in value is greater than 50% of its average cost, the security is written down to its expected recovery value. If only one of the above criteria is met, a further analysis is performed to evaluate the expected recovery value based on third party price targets. If the third party price quotes are below the security’s average cost and one of the other criteria has been met, the decline is considered other-than-temporary, and the security is written down to its expected recovery value.

Property, Plant and Equipment

Property, plant and equipment, including additions and replacements, is recorded at original cost, including labor, materials, asset retirement costs, other direct costs and capitalized interest. The cost of repairs and maintenance, including minor additions and replacements, is charged to expense as incurred. In 2004, 2003 and 2002, the Company capitalized interest costs of $7 million, $18 million and $17 million, respectively.

For electric distribution and transmission property subject to cost-of-service utility rate regulation, the depreciable cost of such property, less salvage value, is charged to accumulated depreciation at retirement. Cost of removal collections from utility customers and expenditures not representing assets retirement obligations (AROs) are recorded as regulatory liabilities or regulatory assets.

For generation-related property, cost of removal not associated with AROs is charged to expense as incurred. The Company

2004 / Page 38

Notes to Consolidated Financial Statements, Continued

records gains and losses upon retirement of generation-related property based upon the difference between proceeds received, if any, and the property’s undepreciated basis at the retirement date.

Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. The Company’s depreciation rates on property, plant and equipment for 2004, 2003 and 2002 are as follows:

	2004	2003	2002
(percent)
Generation	1.97	1.83	1.88
Transmission	1.97	1.96	2.14
Distribution	3.46	3.43	3.55
General and other	5.76	5.47	5.24

Amortization of nuclear fuel used in electric generation is provided on a unit-of-production basis sufficient to fully amortize, over the estimated service life, the cost of the fuel plus permanent storage and disposal costs.

In 2002, the Company extended the estimated useful lives of most of its fossil fuel power stations and electric transmission and distribution property based on depreciation studies that indicated longer lives were appropriate. The changes reduced annual depreciation expense for those assets by approximately $64 million.

Impairment of Long-Lived and Intangible Assets

The Company performs an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. These assets are written down to fair value if the sum of the expected future undiscounted cash flows is less than the carrying amounts.

Regulatory Assets and Liabilities

For utility operations subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will allow for the recovery of current costs through future rates charged to customers, the Company defers these costs as regulatory assets in its financial statements that otherwise would be expensed by nonregulated companies. Likewise, the Company recognizes regulatory liabilities in its financial statements when it is probable that regulators will allow for customer credits through future rates and when revenue is collected from customers for expenditures that are not yet incurred.

Asset Retirement Obligations

Beginning in 2003, the Company recognizes its AROs at fair value as incurred, capitalizing these amounts as costs of the related tangible long- lived assets. Due to the absence of relevant market information, fair value is estimated using discounted cash flow analyses. The Company reports the accretion of the liabilities due to the passage of time as an operating expense. In addition, beginning in 2003, the Company classifies all investments held by its decommissioning trusts as available-for-sale, and recognizes realized gains and losses in other income (loss) and records unrealized gains and losses in AOCI.

Nuclear Decommissioning—2002

In accordance with the accounting policy recognized by regulatory authorities having jurisdiction over its electric utility operations, the Company recognized an expense for the future cost of decommissioning in amounts equal to the sum of amounts collected from ratepayers and earnings on trust investments dedicated to funding the decommissioning of its nuclear plants. The trust investments were reported at fair value with the accumulated provision for decommissioning reported as a liability. Net realized and unrealized earnings on the trust investments, as well as an offsetting expense to increase the accumulated provision for decommissioning, were recorded as a component of other income (loss).

Amortization of Debt Issuance Costs

The Company defers and amortizes debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. As permitted by regulatory authorities, gains or losses resulting from the refinancing of debt allocable to utility operations subject to cost-based rate regulation have also been deferred and amortized over the lives of the new issues.

Note 3. Newly Adopted Accounting Standards

2004

FIN 46R

The Company adopted FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, (FIN 46R) for its interests in VIEs that are not considered special purpose entities on March 31, 2004. As discussed below, the Company adopted FIN 46R for its interests in special purpose entities on December 31, 2003. FIN 46R addresses the identification and consolidation of VIEs, which are entities that are not controllable through voting interests or in which the VIEs’ equity investors do not bear the residual economic risks and rewards in proportion to voting rights. There was no impact on the Company’s results of operations or financial position related to this adoption.

The Company is a party to long-term contracts for purchases of electric generation capacity and energy from qualifying facilities and independent power producers. Certain variable pricing terms in some of these contracts cause them to be considered potential variable interests that require evaluation under the provisions of FIN 46R. If a power generator that holds one of these specific types of contracts is determined to be a VIE and the Company is determined to be the primary beneficiary, the Company would be required to consolidate the entity in its financial statements. Consolidation of one of these potential VIEs would primarily result in the addition of property, plant and equipment, long-term debt and minority interest to the Company’s Consolidated Balance Sheets. The impact on the Company’s Consolidated Statements of Income would be that purchased energy and capacity expenses

2004 / Page 39

Notes to Consolidated Financial Statements, Continued

attributable to the long-term contract with the VIE would be replaced by the VIE’s operations, maintenance and interest expenses. The VIE’s results of operations would be reported as income attributable to a minority interest, and would not affect the Company’s net income. The debt of these potential VIEs, even if included in the Company’s Consolidated Balance Sheets, would be nonrecourse to the Company.

At March 31, 2004, the Company had determined that its power purchase agreements with ten of these entities would require further analysis under FIN 46R. Each of these facilities began commercial operations and service to the Company under the long-term contracts prior to December 31, 2003. Since these entities were established and are legally owned by parties not affiliated with the Company, the Company submitted requests for information needed to evaluate the entity and its contractual relationship with the entity under FIN 46R. In addition, the Company informed the entities that, if the results of its evaluation were to indicate that the Company should consolidate the entity, it would also require periodic financial information in order to perform the accounting required to consolidate the entity in its financial statements. The objectives of the FIN 46R evaluation are to determine: (1) whether the Company’s interest, represented by the power purchase contract, is a significant variable interest; (2) whether the supplier entity is a VIE; and (3) if the supplier entity is a VIE, whether the Company is the primary beneficiary.

In response to these requests, five of the potential VIE supplier entities provided some, but limited, information. After completing its analysis of this information, the Company concluded that one of the supplier entities is a VIE, its power purchase contract represented a significant variable interest in the VIE, but the Company is not its primary beneficiary. In addition, using the limited information received, the Company concluded that it does not hold significant variable interests in two of the potential VIE supplier entities.

Since the enactment of the Virginia Restructuring Act, the Company has sought to renegotiate or terminate long-term power purchase contracts in its efforts to reduce the cost structure of its generation-related operations. In November 2004, the Company paid $92 million to terminate its power purchase agreement and to acquire the related generating facility from one of the potential VIE suppliers that had not provided information in response to the Company’s FIN 46R request. The Company had purchased $20 million, $20 million and $21 million of electric generation capacity and $4 million, $7 million and $3 million of electric energy under this power purchase agreement in 2004, 2003 and 2002, respectively. In addition, in February 2005, the Company paid $42 million in cash and assumed $62 million of debt to terminate its power purchase agreement and to acquire the related generating facility from the supplier entity that the Company had determined to be a VIE and, in which, its power purchase agreement represented a significant variable interest. The Company purchased $23 million, $23 million and $24 million of electric generation capacity and $8 million, $10 million and $5 million of electric energy under this power purchase agreement in 2004, 2003 and 2002, respectively.

For those six potential VIE supplier entities that have not provided sufficient information, the Company will continue its efforts to obtain information and will complete an evaluation of its relationship with each of these potential VIEs, if sufficient information is ultimately obtained. The Company has remaining purchase commitments with these six potential VIE supplier entities of $2.6 billion at December 31, 2004. These commitments are incorporated in the Company’s disclosure of unconditional purchase obligations included in Note 19. The Company paid $249 million, $250 million and $300 million for electric generation capacity and $185 million, $168 million and $120 million for electric energy to these entities in 2004, 2003 and 2002, respectively. The Company’s exposure to losses from its involvement with these entities cannot be determined since losses, if any, would be represented by either: 1) the difference between (a) the amount payable by the Company for energy and capacity under the long-term contract and (b) amounts recoverable through sales to retail electric customers in its service territory or wholesale market transactions; or 2) if the potential VIE supplier fails to perform, any amount paid by the Company to obtain replacement energy and capacity in excess of the amounts otherwise payable under the long-term contract with the potential VIE supplier entity.

The Emerging Issues Task Force (EITF) has added a project to its agenda to consider what variability should be considered when determining whether an interest is a variable interest. It is uncertain how this EITF project or other future efforts to further interpret FIN 46R could impact the Company’s conclusions based on its use of information received.

2003

SFAS No. 143

Effective January 1, 2003, the Company adopted SFAS No. 143, which provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. The effect of adopting SFAS No. 143 for 2003, as compared to an estimate of net income reflecting the continuation of former accounting policies, was to increase net income by $160 million. The increase was comprised of a $139 million after-tax gain, representing the cumulative effect of a change in accounting principle and an increase in income before the cumulative effect of a change in accounting principle of $21 million.

EITF 02-3

On January 1, 2003, the Company adopted EITF Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, that rescinded EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. Adopting EITF 02-3 resulted in the discontinuance of fair value accounting for non-derivative contracts held for trading purposes. Those contracts are recognized as revenue or expense at the time of contract performance, settle - -

2004 / Page 40

Notes to Consolidated Financial Statements, Continued

ment or termination. The EITF 98-10 rescission was effective for non-derivative energy trading contracts initiated after October 25, 2002. For all non-derivative energy trading contracts initiated prior to October 25, 2002, the Company recognized a loss of $90 million ($55 million after-tax) as the cumulative effect of this change in accounting principle on January 1, 2003.

EITF 03-11

On October 1, 2003, the Company adopted EITF Issue No. 03-11, Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes” as Defined in Issue No. 02-3, on October 1, 2003. EITF 03-11 addresses classification of income statement related amounts for derivative contracts. Income statement amounts related to periods prior to October 1, 2003 are presented as originally reported. See Note 2.

Statement 133 Implementation Issue No. C20

In connection with a request to reconsider an interpretation of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, 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. Issue C20 establishes criteria for determining whether a contract’s pricing terms that contain broad market indices (e.g., the consumer price index) could qualify as a normal purchase or sale and, therefore, not be subject to fair value accounting. The Company has several contracts that qualify as normal purchase and sales contracts under the Issue C20 guidance. However, the adoption of Issue C20 required the contracts to be initially recorded at fair value as of October 1, 2003, resulting in the recognition of an after-tax charge of $101 million, representing the cumulative effect of the change in accounting principle. As normal purchase and sales, these contracts are not subject to fair value accounting.

FIN 46R

On December 31, 2003, the Company adopted FIN 46R for its interests in special purpose entities, resulting in the consolidation of a special purpose lessor entity through which the Company had constructed, financed and leased a power generation project. As a result, the Consolidated Balance Sheet as of December 31, 2003 reflects an additional $364 million in net property, plant and equipment and deferred charges and $370 million of related debt. This resulted in additional depreciation expense of approximately $10 million in 2004. The cumulative effect in 2003 of adopting FIN 46R for the Company’s interests in the special purpose entity was an after-tax charge of $4 million, representing depreciation and amortization expense associated with the consolidated assets.

In 2002, the Company established Virginia Power Capital Trust II, 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. Upon adoption of FIN 46R, the Company began reporting as long-term debt its junior subordinated notes held by the trust rather than the trust preferred securities. As a result, in 2004, the Company reported interest expense on the junior subordinated notes rather than preferred distribution expense on the trust preferred securities.

2002

Pro Forma Information Reflecting the Adoption of New Standards

Disclosure requirements associated with the adoption of FIN 46R and SFAS No. 143 require a disclosure of pro forma net income for 2002 as if the Company had applied the provisions of those standards as of January 1, 2002. Had the Company applied those standards during 2002, net income would have been $778 million. Other standards adopted during 2004 and 2003 do not require pro forma information and are excluded from this amount.

Note 4. Recently Issued Accounting Standards

EITF 03-1

In accordance with FSP EITF 03-1-1, the Company delayed its adoption of the recognition and measurement provisions of EITF 03-1, The Meaning of Other-Than Temporary Impairment and Its Application to Certain Investments, which provides guidance for evaluating and recognizing other-than-temporary impairments for certain investments in debt and equity securities. This delay will be in effect until the FASB reaches a final conclusion on issues raised in its proposed FSP 03-1-a, which relates primarily to implementation issues concerning certain types of debt securities.

Pending the adoption of any new guidance that may be finalized in the future, the Company has continued to evaluate its available-for-sale securities for other-than-temporary impairment based upon the accounting policy described in Note 2. In addition to issues being addressed by the FASB in FSP 03-1-a, the Company and other entities in the electric industry have sought additional guidance from the FASB concerning the proper application of EITF 03-1 to debt and equity securities held in nuclear decommissioning trusts. Given the delayed effective date and the request for additional guidance described above, the Company cannot predict what the initial or ongoing impact of applying EITF 03-1 to its nuclear decommissioning trust investments may have on its results of operations and financial condition at this time.

SFAS No. 151

In November 2004, the FASB issued SFAS No. 151, Inventory Costs—an amendment of ARB No. 43, Chapter 4, which clarifies that abnormal amounts of idle facility expense, handling costs, freight, and wasted materials (spoilage) should be recognized as current period charges, and requires that in manufacturing operations, allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facility. The Company will adopt the provisions of this standard prospectively beginning January 1, 2006 and does not expect the adoption to have a material impact on its results of operations and financial condition.

2004 / Page 41

Notes to Consolidated Financial Statements, Continued

SFAS No. 153

In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29, which requires that all commercially substantive exchange transactions, for which the fair value of the assets exchanged are reliably determinable, be recorded at fair value, whether or not they are exchanges of similar productive assets. This amends the exception from fair value measurements in APB No 29, Accounting for Nonmonetary Transactions, for nonmonetary exchanges of similar productive assets and replaces it with an exception for only those exchanges that do not have commercial substance. The Company will adopt the provisions of this standard prospectively beginning July 1, 2005 and does not expect the adoption to have a material impact on its results of operations and financial condition.

Note 5. Operating Revenue

The Company’s operating revenue consists of the following:

	Year Ended December 31,
	2004			2003		2002
(millions)
Regulated electric sales	$	5,180		$	4,876	$	4,857
Nonregulated electric sales		(141	)		44		78
Nonregulated gas sales		42			263		(58	)
Other		660			254		95
Total operating revenue	$	5,741		$	5,437	$	4,972

Note 6. Income Taxes

Details of income tax expense were as follows:

	Year Ended December 31,
	2004			2003			2002
(millions)
Current expense:
Federal	$	79		$	87		$	297
State		35			4			30
Total current		114			91			327
Deferred expense:
Federal		140			220			90
State		1			41			25
Total deferred		141			261			115
Amortization of deferred investment tax credits, net		(16	)		(16	)		(17	)
Total income tax expense	$	239		$	336		$	425

The statutory U.S. federal income rate reconciles to the effective income tax rates as follows:

	Year Ended December 31,
	2004		2003		2002
U.S statutory rate	35.0	%	35.0	%	35.0	%
Increases (reductions) resulting from:
Utility plant differences	0.2		(0.6	)	(0.2	)
Amortization of investment tax credits	(1.8	)	(1.3	)	(1.1	)
State income tax, net of federal tax benefit	3.6		3.2		3.0
Employee stock ownership plan deduction	(0.7	)	—		—
Other, net	(0.6	)	0.3		(1.2	)
Effective tax rate	35.7	%	36.6	%	35.5	%

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The Company’s net deferred income taxes consist of the following:

	December 31,
	2004		2003
(millions)
Deferred income tax assets:
Deferred investment tax credits	$	25	$	31
Other		112		54
Total deferred income tax assets		137		85
Deferred income tax liabilities:
Depreciation method and plant basis differences		1,912		1,766
Income taxes recoverable through future rates		20		15
Deferred state income tax		123		131
Other		170		83
Total deferred income tax liabilities		2,225		1,995
Total net deferred income tax liabilities(1)	$	2,088	$	1,910

(1) At December 31, 2004 and 2003, total net deferred income tax liabilities include $112 million and $54 million, respectively, of current deferred tax assets that were reported in other current assets.

As a matter of course, the Company is regularly audited by federal and state tax authorities. The Company establishes liabilities for probable tax-related contingencies and reviews them in light of changing facts and circumstances. Although the results of these audits are uncertain, the Company believes that the ultimate outcome will not have a material adverse effect on the Company’s financial position. The Company had no significant tax-related contingent liabilities at December 31, 2004.

At December 31, 2004, the Company had the following loss and credit carryforwards:

• Federal loss carryforwards of $18 million that expire if unutilized during the period 2023 through 2024;

• State net operating loss carryforwards of $216 million that expire if unutilized during the period 2021 through 2024; and

• Federal and state minimum tax credits of $19 million that do not expire.

2004 / Page 42

Notes to Consolidated Financial Statements, Continued

American Jobs Creation Act of 2004 (the Act)

The Act was signed into law October 22, 2004, and has several provisions for energy companies including a deduction related to taxable income derived from qualified production activities. Under the Act, qualified production activities include the Company’s electric generation activities. The Act limits the deduction to the lesser of taxable income derived from qualified production activities or the consolidated federal taxable income of Dominion and its subsidiaries. At this time, the Company does not believe the qualified production activities deduction will have a material impact on the Company’s results of operations or financial position in 2005.

Note 7. Hedge Accounting Activities

The Company is exposed to the impact of market fluctuations in the price of natural gas, electricity and other energy-related commodities marketed and purchased as well as currency exchange and interest rate risks of its business operations. The Company uses derivative instruments to mitigate its exposure to these risks and designates derivative instruments as fair value or cash flow hedges for accounting purposes.

During 2004, in connection with fair value hedges of natural gas inventory, the Company recognized in net income $1 million of losses as hedge ineffectiveness and $3 million of gains attributable to differences between spot prices and forward prices that are excluded from the measurement of effectiveness under the hedge strategy.

The following table presents selected information related to cash flow hedges included in AOCI in the Consolidated Balance Sheet at December 31, 2004:

	Accumulated Other Comprehensive Income After-Tax		Portion Expected to be Reclassified to Earnings During the Next 12 Months After-Tax		Maximum Term
(millions)
Commodities—Gas	$	6	$	6	7 months
Interest Rate		1		—	130 months
Foreign Currency		31		6	35 months
Total	$	38	$	12

The actual amounts that will be reclassified to earnings in 2005 will vary from the expected amounts presented above as a result of changes in market prices, 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.

Note 8. Nuclear Decommissioning Trust Funds

The Company holds marketable debt and equity securities in nuclear decommissioning trust funds. These investments are classified as available-for-sale. As described below, prior to adopting SFAS No. 143, the Company did not record unrealized gains and losses in AOCI, but rather in earnings, offset by a provision for future decommissioning costs. The Company’s decommissioning trust funds, as of December 31, 2004, are summarized below.

	Fair Value		Total Unrealized Gains included in AOCI		Total Unrealized Losses included in AOCI (1)
(millions)
2004
Equity securities	$	678	$	145	$	3
Debt securities		392		9		1
Cash and other		49		—		—
Total	$	1,119	$	154	$	4
2003
Equity securities	$	592	$	98	$	—
Debt securities		382		3		1
Cash and other		36		—		—
Total	$	1,010	$	101	$	1

(1) In 2004, approximately $1 million of unrealized losses relate primarily to equity securities in a loss position for greater than 1 year. There were no securities in an unrealized loss position for greater than 1 year in 2003.

The fair value of debt securities at December 31, 2004 by contractual maturity are as follows:

	Amount
(millions)
Due in one year or less	$	17
Due after one year through five years		132
Due after five years through ten years		154
Due after ten years		89
Total	$	392

For 2004, proceeds from the sale of available-for-sale securities totaled $237 million; gross realized gains totaled $27 million and gross realized losses totaled $24 million. In determining realized gains and losses, the cost of these securities was determined on a specific identification basis.

Decommissioning Trust Investments—2002

Prior to adopting SFAS No. 143, the Company recognized an expense for the future cost of decommissioning its nuclear plants equal to the amounts collected from ratepayers and earnings on trust investments dedicated to funding the decommissioning of those plants. The trusts were reported at fair value with realized and unrealized earnings on the trust investments, as well as an offsetting expense to increase the accumulated provision for decommissioning, recorded as a component of other income (loss). In 2002, the Company recognized net realized gains and interest income of $11 million and net unrealized losses of $67 million related to the trusts.

2004 / Page 43

Notes to Consolidated Financial Statements, Continued

Note 9. Property, Plant and Equipment

Major classes of property, plant and equipment and their respective balances are:

December 31,
	2004		2003
(millions)
Utility:
Generation	$	10,135	$	9,780
Transmission		1,635		1,592
Distribution		6,025		5,796
Nuclear fuel		795		757
General and other		608		616
Plant under construction		511		575
		19,709		19,116
Non-utility—Other		7		13
Total property, plant and equipment	$	19,716	$	19,129

Jointly-Owned Utility Plants

The Company’s proportionate share of jointly-owned utility plants at December 31, 2004 follows:

	Bath County Pumped Storage Station		North Anna Power Station		Clover Power Station
(millions, except percentages)
Ownership interest		60.0%		88.4%		50.0%
Plant in service	$	1,014	$	2,067	$	548
Accumulated depreciation		378		897		112
Nuclear fuel		—		380		—
Accumulated amortization of nuclear fuel		—		285		—
Plant under construction		27		47		3

The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly owned facilities in the same proportion as their respective ownership interest. The Company reports its share of operating costs in the appropriate operating expense (fuel, other operations and maintenance, depreciation and amortization and other taxes, etc.) in the Consolidated Statements of Income.

Note 10. Intangible Assets

All of the Company’s intangible assets are subject to amortization. Amortization expense for intangible assets was $27 million, $25 million and $24 million for 2004, 2003 and 2002, respectively. There were no material acquisitions of intangible assets in 2004 or 2003. Intangible assets are included in other assets on the Consolidated Balance Sheets. The components of intangible assets at December 31, 2004 and 2003 were as follows:

	2004				2003
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
(millions)
Software and software licenses	$	265	$	129	$	254	$	113
Other		50		9		16		7
Total	$	315	$	138	$	270	$	120

Annual amortization expense for intangible assets is estimated to be $32 million for 2005, $27 million for 2006, $23 million for 2007, $14 million for 2008 and $11 million for 2009.

Note 11. Regulatory Assets and Liabilities

The Company’s regulatory assets and liabilities include the following:

December 31,
	2004		2003
(millions)
Regulatory assets:
Income taxes recoverable through future rates(1)	$	51	$	43
Cost of decommissioning DOE uranium enrichment facilities(2)		18		27
Deferred fuel(3)		248		335
Regional transmission organization start-up and integration costs(4)		31		20
Other		13		13
Total regulatory assets	$	361	$	438
Regulatory liabilities:
Provision for future cost of removal(5)	$	374	$	359
Other(6)		13		15
Total regulatory liabilities	$	387	$	374

(1) Income taxes recoverable through future rates resulted from the recognition of additional deferred income taxes, not previously recorded under past ratemaking practices.

(2) The cost of decommissioning the Department of Energy’s (DOE) uranium enrichment facilities represents the unamortized portion of the Company’s required contributions to a fund for decommissioning and decontaminating the DOE’s uranium enrichment facilities. The contributions began in 1992 and will continue over a 15-year period with escalation for inflation. These costs are currently being recovered in fuel rates.

(3) Deferred fuel accounting provides that the difference between 1) reasonably incurred actual cost of fuels used in electric generation and energy purchases and 2) the recovery for such costs included in current rates were deferred and matched against future revenue. Deferred fuel costs were historically recovered within two years; however, in connection with the settlement of the 2003 Virginia fuel rate proceeding, the Company agreed to recover $307 million of previously incurred costs through June 30, 2007 without a return on unrecovered balances.

(4) The Federal Energy Regulatory Commission (FERC) has authorized the deferral of start-up costs incurred by transmission owning companies joining a Regional Transmission Organization (RTO). The Company has deferred $4 million in start-up costs associated with the Alliance Regional Transmission Organization (ARTO) and $24 million associated with the PJM RTO and associated carrying costs of $3 million. The Company expects recovery from Virginia jurisdictional retail customers to commence at the end of the Virginia retail rate cap period, subject to regulatory approval.

(5) Rates charged to customers by the Company’s regulated business include a provision for the cost of future activities to remove assets expected to be incurred at the time of retirement.

(6) The Company’s other regulatory liability represents the excess of the accumulated provision for nuclear decommissioning accrued under its prior accounting policy for decommissioning, which was based on amounts being collected from the Company’s North Carolina jurisdictional customers to fund future decommissioning activities, over the amounts recognized under SFAS No. 143.

At December 31, 2004, approximately $282 million of the Company’s regulatory assets represented past expenditures on which it does not earn a return. These expenditures consist

2004 / Page 44

Notes to Consolidated Financial Statements, Continued

primarily of regional transmission organization start-up and integration costs and a portion of deferred fuel costs.

Note 12. Asset Retirement Obligations

The Company’s AROs are primarily associated with the decommissioning of its nuclear generation facilities. The changes to the Company’s AROs during 2004 were as follows:

	Amount
(millions)
Asset retirement obligations at December 31, 2003	$	740
Obligations settled during the period		(1	)
Accretion expense		42
Asset retirement obligations at December 31, 2004	$	781

The Company has established trusts dedicated to funding the future decommissioning of its nuclear plants. At December 31, 2004 and 2003, the aggregate fair value of these trusts, consisting primarily of debt and equity securities, totaled $1.1 billion and $1.0 billion, respectively.

Note 13. Short-term Debt and Credit Agreements

In May 2004 and 2002, Dominion, Consolidated Natural Gas Company (CNG), a wholly-owned subsidiary of Dominion, and the Company entered into two joint credit facilities that allow aggregate borrowings of up to $2.25 billion. The facilities include a $1.5 billion three-year revolving credit facility that terminates in May 2007 and a $750 million three-year revolving credit facility that terminates in May 2005. It is expected that the $750 million credit facility will be renewed prior to its maturity. These credit facilities are being used for working capital, as support for the combined commercial paper programs of Dominion, CNG and the Company and other general corporate purposes. The $1.5 billion and $750 million credit facilities can also be used to support the issuance of up to $500 million and $200 million of letters of credit, respectively.

At December 31, 2004, total outstanding commercial paper supported by the joint credit facilities was $573 million, of which the Company’s borrowings were $267 million, with a weighted average interest rate of 2.35%. At December 31, 2003, total outstanding commercial paper supported by previous credit agreements was $1.44 billion, of which the Company’s borrowings were $717 million, with a weighted average interest rate of 1.17%.

At December 31, 2004, total outstanding letters of credit supported by the joint credit facilities were $183 million, of which a total of $104 million was issued on behalf of an unregulated subsidiary of the Company. At December 31, 2003, total outstanding letters of credit supported by the joint credit facilities were $85 million, of which a total of $62 million was issued on the behalf of an unregulated subsidiary of the Company.

2004 / Page 45

Notes to Consolidated Financial Statements, Continued

Note 14. Long-term Debt

Long-term debt consists of the following:

December 31,	2004 Weighted Average Coupon(1)		2004			2003
(millions, except percentages)
Long-Term Debt
Secured First and Refunding Mortgage Bonds(2):
7.625% to 8.0%, due 2004 to 2007	7.63	%	$	215		$	465
7.0% to 8.625%, due 2024 to 2025	8.09			512			512
Unsecured Senior and Medium-Term Notes:
5.375% to 7.2%, due 2004 to 2008	5.57			1,370			1,445
4.50% to 7.25%, due 2010 to 2025	5.08			936			830
Unsecured Callable and Puttable Enhanced SecuritiesSM, 4.10% due 2038(3)	—			225			225
Tax-Exempt Financings(4):
Variable rate, due 2008	1.33			60			60
Variable rates, due 2015 to 2027	1.34			137			137
4.95% to 9.62%, due 2004 to 2008	5.24			108			107
2.225% to 7.65%, due 2009 to 2031	5.32			397			295
Secured Bank Debt:
Variable rate, due 2007(5)	1.75			370			370
Notes Payable to Affiliates
Unsecured Junior Subordinated Notes Payable to Affiliated Trust, 7.375%, due 2042	—			412			412
Note Payable to Parent, 2.125%, due 2023	—			220			220
				4,962			5,078
Fair value hedge valuation(6)				1			2
Amount due within one year	7.51			(12	)		(325	)
Unamortized discount and premium, net				7			(11	)
Total long-term debt			$	4,958		$	4,744

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2004.

(2) Substantially all of the Company’s property is subject to the lien of the mortgage, securing its mortgage bonds.

(3) On December 15, 2008, $225 million of the 4.10% Callable and Puttable Enhanced Securities^SM due 2038 are subject to redemption at par plus accrued interest, unless holders of related options exercise rights to purchase and remarket the notes.

(4) Certain pollution control equipment at the Company’s generating facilities has been pledged to support these financings. The variable rate tax-exempt financings are supported by a stand-alone $200 million three-year credit facility that terminates in May 2006.

(5) Represents debt associated with a special purpose lessor entity that is consolidated in accordance with FIN 46R. The debt is nonrecourse to the Company and is secured by the entity’s property, plant and equipment of $346 million and $359 million at December 31, 2004 and 2003, respectively.

(6) Represents changes in fair value of certain fixed rate long-term debt associated with fair value hedging relationships.

Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2004 were as follows (in millions):

2005		2006		2007		2008		2009		Thereafter		Total
$	12	$	613	$	1,263	$	285	$	123	$	2,666	$	4,962

The Company’s short-term credit facilities and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2004, there were no events of default under the Company’s covenants.

Junior Subordinated Notes Payable to Affiliated Trust

In 2002, the Company established a subsidiary capital trust, Virginia Power Capital Trust II (trust), a finance subsidiary of the Company, which holds 100% of the voting interests, sold 16 million 7.375% trust preferred securities for $400 million, representing preferred beneficial interests and 97% beneficial ownership in the assets held by the trust. In exchange for the $400 million realized from the sale of the trust preferred securities and $12 million of common securities that represent the remaining 3% beneficial ownership interest in the assets held by the capital trust, the Company issued $412 million of its 2002 7.375% junior subordinated notes (junior subordinated notes) due July 30, 2042. The junior subordinated notes constitute 100% of the trust’s assets. The trust must redeem its trust preferred

2004 / Page 46

Notes to Consolidated Financial Statements, Continued

securities when the junior subordinated notes are repaid at maturity or if redeemed, prior to maturity.

Under previous accounting guidance, the Company consolidated the trust as preferred securities of subsidiary trust in the preparation of its Consolidated Financial Statements. In accordance with FIN 46R, the Company ceased to consolidate the trust as of December 31, 2003 and instead reports as long-term debt on its Consolidated Balance Sheet the junior subordinated notes issued by the Company and held by the trust.

Distribution payments on the trust preferred securities held by the trust are considered to be fully and unconditionally guaranteed by the Company, when all of the related agreements are taken into consideration. Each guarantee agreement only provides for the guarantee of distribution payments on the trust preferred securities to the extent that the trust has funds legally and immediately available to make distributions. The trust’s ability to pay amounts when they are due on the trust preferred securities is dependent solely upon the Company’s payment of amounts when they are due on the junior subordinated notes. If the payment on the junior subordinated notes is deferred, the Company may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments. Also, during the deferral period, the Company may not make any payments or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the junior subordinated notes.

Note 15. Preferred Stock

The Company is authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference. Upon involuntary liquidation, dissolution or winding-up of the Company, each share is entitled to receive $100 per share plus accrued dividends. Dividends are cumulative.

Holders of the outstanding preferred stock of the Company are not entitled to voting rights except under certain provisions of the amended and restated articles of incorporation and related provisions of Virginia law restricting corporate action, or upon default in dividends, or in special statutory proceedings and as required by Virginia law (such as mergers, consolidations, sales of assets, dissolution and changes in voting rights or priorities of preferred stock.)

In 2002, the Company issued 1,250 units consisting of 1,000 shares per unit of cumulative preferred stock for $125 million. The preferred stock has a dividend rate of 5.50% until the end of the initial dividend period on December 20, 2007. The dividend rate for subsequent periods will be determined according to periodic auctions. Except during the initial dividend period, and any non-call period, the preferred stock will be redeemable, in whole or in part, on any dividend payment date at the option of the Company. The Company may also redeem the preferred stock, in whole but not in part, if certain changes are made to federal tax law which reduce the dividends received deduction percentage.

Presented below are the series of preferred stock not subject to mandatory redemption that were outstanding as of December 31, 2004:

Dividend	Issued and Outstanding Shares	Entitled Per Share Upon Liquidation
	(thousands)
$5.00	107	$	112.50
4.04	13		102.27
4.20	15		102.50
4.12	32		103.73
4.80	73		101.00
7.05	500		103.18	(1)
6.98	600		103.15	(2)
Flex MMP 12/02, Series A	1,250		100.00
Total	2,590

(1) Through 7/31/05; $102.82 commencing 8/1/05; amounts decline in steps thereafter to $100.00.

(2) Through 8/31/05; $102.80 commencing 9/1/05; amounts decline in steps thereafter to $100.00.

Note 16. Shareholder’s Equity

Common Stock

In 2004, as approved by the Virginia State Corporation Commission (Virginia Commission), Dominion made an equity investment in the Company through the purchase of the Company’s common stock. The Company issued 20,115 shares of its common stock to Dominion for cash consideration of $500 million.

Other Paid-In Capital

In 2004 and 2003, the Company recorded $11 million and $21 million, respectively, of other paid-in capital in connection with the reduction in amounts payable to Dominion.

Accumulated Other Comprehensive Income

Presented in the table below is a summary of AOCI by component:

December 31,	2004		2003
(millions)
Net unrealized gains on derivatives—-hedging activities, net of tax	$	38	$	21
Net unrealized gains on nuclear decommissioning trust funds, net of tax		91		61
Total accumulated other comprehensive income	$	129	$	82

Note 17. Dividend Restrictions

The 1935 Act and related regulations issued by the Securities and Exchange Commission (SEC) impose restrictions on the transfer and receipt of funds by a registered holding company, like Dominion, from its subsidiaries, including the Company. The restrictions include a general prohibition against loans or advances being made by the subsidiaries to benefit the registered holding company. Under the 1935 Act, registered holding companies and their subsidiaries may pay dividends only

2004 / Page 47

Notes to Consolidated Financial Statements, Continued

from retained earnings, unless the SEC specifically authorizes payments from other capital accounts. In 2004, the SEC granted relief, authorizing the Company’s non-utility subsidiaries to pay dividends out of capital or unearned surplus in situations where such subsidiary has received excess cash from an asset sale, engaged in a restructuring, or is returning capital to an associate company.

The Virginia Commission may prohibit any public service company from declaring or paying a dividend to an affiliate, if found not to be in the public interest. As of December 31, 2004, the Virginia Commission had not restricted the payment of dividends by the Company.

Certain agreements associated with the Company’s joint credit facilities with Dominion and CNG contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict the Company’s ability to pay dividends to Dominion or to receive dividends from its subsidiaries at December 31, 2004.

See Note 14 for a description of potential restrictions on dividend payments by the Company in connection with the deferral of distribution payments on trust preferred securities.

Note 18. Employee Benefit Plans

The Company participates in a defined benefit pension plan sponsored by Dominion. Benefits payable under the plan are based primarily on years of service, age and the employee’s compensation. As a participating employer, the Company is subject to Dominion’s funding policy, which is to generally contribute annually an amount that is in accordance with the provisions of the Employment Retirement Income Security Act of 1974. The Company’s net periodic pension cost was $40 million, $23 million and $7 million in 2004, 2003 and 2002, respectively. The Company’s contributions to the pension plan were $108 million and $37 million in 2003 and 2002, respectively. The Company did not contribute to the pension plan in 2004.

The Company participates in plans that provide certain retiree health care and life insurance benefits to multiple Dominion subsidiaries. Annual premiums are based on several factors such as age, retirement date and years of service. The Company’s net periodic benefit cost was $44 million, $44 million and $34 million in 2004, 2003 and 2002, respectively.

Certain regulatory authorities have held that amounts recovered in rates for other postretirement benefits in excess of benefits actually paid during the year must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, the Company funds postretirement benefit costs through Voluntary Employees’ Beneficiary Associations. The Company’s contributions to health care and life insurance plans were $34 million, $31 million and $17 million in 2004, 2003 and 2002, respectively.

The Company also participates in Dominion-sponsored employee savings plans that cover substantially all employees. Employer matching contributions of $11 million, $10 million and $10 million were incurred in 2004, 2003 and 2002, respectively.

Note 19. Commitments and Contingencies

As the result of issues generated in the ordinary course of business, the Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies, some of which involve substantial amounts of money. Management believes that the final disposition of these proceedings will not have a material effect on the Company’s financial position, liquidity or results of operations.

Long-Term Purchase Agreements

Unconditional purchase obligations as defined by accounting standards are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third parties have used to secure financing that will provide the contracted goods or services. Presented below is a summary of the Company’s agreements as of December 31, 2004:

	2005		2006		2007		2008		2009		Thereafter		Total
(millions)
Purchased electric capacity(1)	$	509	$	496	$	472	$	440	$	418	$	3,103	$	5,438

(1) Commitments represent estimated amounts payable for capacity under power purchase contracts with qualifying facilities and independent power producers. Capacity payments under the contracts are generally based on fixed dollar amounts per month, subject to escalation using broad-based economic indices, and payments for energy are based on the applicable pricing times the units of electrical energy delivered. At December 31, 2004, the present value of the total commitment for capacity payments is $3.4 billion. Capacity payments totaled $570 million, $611 million and $661 million, and energy payments totaled $293 million, $289 million and $219 million for 2004, 2003, and 2002, respectively.

In 2004, the Company paid $153 million in cash and assumed $213 million of debt in connection with the termination of three long-term power purchase agreements and the acquisition of the related generating facilities used by non-utility generators to provide electricity to the Company. In connection with the termination of the agreements, the Company recorded after-tax charges totaling $43 million. These charges include the reversal of a $167 million pre-tax contract liability associated with one of the terminated agreements. The contract liability represented the remaining balance of the fair value recorded in October 2003 upon adoption of SFAS No. 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, (Issue C20). The power purchase agreement, which contained pricing terms linked to a broad market index, had to be recorded at fair value upon adoption of Issue C20; however, since it qualified as a normal purchase and sale contract, no further changes in its fair value were recognized. In 2003, the Company paid $154 million for the purchase of a generating facility and the termination of two long-term power purchase agreements with non-utility generators. The Company recorded after-tax charges totaling $65 million for the termination of the long-term power purchase agreements. The Company allocates the purchase price to the assets and liabilities

2004 / Page 48

Notes to Consolidated Financial Statements, Continued

acquired and the terminated agreements based on their estimated fair values as of the date of acquisition.

In the fourth quarter of 2004, the Company recorded a $112 million after-tax charge related to its interest in a long-term power tolling contract with a 551 megawatt combined cycle facility located in Batesville, Mississippi. The Company decided to divest its interest in the long-term power tolling contract in connection with Dominion’s reconsideration of the scope of certain activities of the Clearinghouse, including those conducted on behalf of the Company’s business segments, and Dominion’s ongoing strategy to focus on business activities within the MAIN to Maine region. The charge is based on the Company’s evaluation of preliminary bids received from third parties, reflecting the expected amount of consideration that would be required by a third party for its assumption of the Company’s interest in the contract in the first quarter of 2005.

Lease Commitments

The Company leases various facilities, vehicles and equipment under both operating and capital leases. Payments under certain leases are escalated based on an index such as the consumer price index. Future minimum lease payments under noncancelable operating and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 2004 are as follows (in millions):

2005	2006		2007		2008		2009		Thereafter		Total
$36	$	25	$	20	$	15	$	11	$	29	$	136

Rental expense totaled $40 million, $49 million and $52 million for 2004, 2003 and 2002, respectively, the majority of which is reflected in other operations and maintenance expense.

Environmental Matters

The Company is subject to costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.

Historically, the Company recovered such costs arising from regulated electric operations through utility rates. However, to the extent that environmental costs are incurred in connection with operations regulated by the Virginia Commission during the period ending December 31, 2010, in excess of the level currently included in the Virginia jurisdictional electric retail rates, the Company’s results of operations will decrease. After that date, the Company may seek recovery through rates of only those environmental costs related to regulated electric transmission and distribution operations.

Superfund Sites

From time to time, the Company may be identified as a potentially responsible party to a Superfund site. The Environmental Protection Agency (EPA) (or a state) can either (a) allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or (b) conduct the remedial investigation and action and then seek reimbursement from the parties. Each party can be held jointly, severally and strictly liable for all costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, the Company may be responsible for the costs of remedial investigation and actions under the Superfund Act or other laws or regulations regarding the remediation of waste. The Company does not believe that any currently identified sites will result in significant liabilities.

In 1987, the EPA identified the Company and a number of other entities as Potentially Responsible Parties (PRPs) at two Superfund sites located in Kentucky and Pennsylvania. In 2003, the EPA issued its Certificate of Completion of remediation for the Kentucky site. Future costs for the Kentucky site will be limited to minor operations and maintenance expenditures. Remediation design is ongoing for the Pennsylvania site, and total remediation costs are expected to be in the range of $13 million to $25 million. Based on allocation formulas and the volume of waste shipped to the site, the Company has accrued a reserve of $2 million to meet its obligations at these two sites. Based on a financial assessment of the PRPs involved at these sites, the Company has determined that it is probable that the PRPs will fully pay their share of the costs. The Company generally seeks to recover its costs associated with environmental remediation from third party insurers. At December 31, 2004, any pending or possible claims were not recognized as an asset or offset against such obligations.

Other EPA Matters

In relation to a Notice of Violation received by the Company in 2000 from the EPA, the Company entered into a Consent Decree settlement in 2003 and committed to improve air quality. The Company has already incurred certain capital expenditures for environmental improvements at its coal-fired stations in Virginia and West Virginia. The Company continues to commit to additional measures in its current financial plans and capital budget to satisfy the requirements of the Consent Decree.

Nuclear Operations

Nuclear Decommissioning—Minimum Financial Assurance

The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of its nuclear facilities. The Company’s 2004 NRC minimum financial assurance amount, aggregated for the nuclear units, was $1.3 billion and has been satisfied by a combination of guarantees and the funds being collected and deposited in the trusts.

Nuclear Insurance

The Price-Anderson Act provides the public up to $10.8 billion of protection per nuclear incident via obligations required of owners of nuclear power plants. The Price-Anderson Act Amendment of 1988 allows for an inflationary provision adjustment every five years. The Company has purchased $300 million of coverage from commercial insurance pools with the remainder provided through a

2004 / Page 49

Notes to Consolidated Financial Statements, Continued

mandatory industry risk-sharing program. In the event of a nuclear incident at any licensed nuclear reactor in the United States, the Company could be assessed up to $100.6 million for each of its four licensed reactors, not to exceed $10 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.

The Price-Anderson Act was first enacted in 1957 and has been renewed three times—in 1967, 1975 and 1998. The Price-Anderson Act expired on August 31, 2002, but operating nuclear reactors continue to be covered by the law. Congress is currently holding hearings to reauthorize the legislation.

The Company’s current level of property insurance coverage ($2.55 billion each for North Anna and Surry) exceeds the NRC’s minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site and includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first to return the reactor to and maintain it in a safe and stable condition and second to decontaminate the reactor and station site in accordance with a plan approved by the NRC. The Company’s nuclear property insurance is provided by Nuclear Electric Insurance Limited (NEIL), a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. The maximum assessment for the current policy period is $52 million. Based on the severity of the incident, the board of directors of the Company’s nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. The Company has the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination.

The Company purchases insurance from NEIL to cover the cost of replacement power during the prolonged outage of a nuclear unit due to direct physical damage of the unit. Under this program, the Company is subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. The current policy period’s maximum assessment is $20 million.

The North Anna Power Station is jointly owned by Old Dominion Electric Cooperative, as discussed in Note 9. The co-owner is responsible for its share of the nuclear decommissioning obligation and insurance premiums, including any retrospective premium assessments and any losses not covered by insurance.

Spent Nuclear Fuel

Under provisions of the Nuclear Waste Policy Act of 1982, the Company has entered into a contract with the DOE for the disposal of spent nuclear fuel. The DOE failed to begin accepting the spent nuclear fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by the Company’s contract with the DOE. In January 2004, Dominion and the Company filed a lawsuit in the United States Court of Federal Claims against the DOE in connection with its failure to commence accepting spent nuclear fuel. The Company will continue to safely manage its spent fuel until it is accepted by the DOE.

Litigation

The Company and Dominion Telecom, Inc. (Dominion Telecom) were defendants in a class action lawsuit whereby the plaintiffs claimed that the Company and Dominion Telecom strung fiber-optic cable across their land along an electric transmission corridor without paying compensation. The plaintiffs sought damages for trespass and “unjust enrichment,” as well as punitive damages from the defendants. In April 2004, the parties entered into a settlement agreement that was subsequently approved by the court in July 2004. Under the terms of the settlement, a fund of $20 million was established by the Company to pay claims of current and former landowners as well as fees of lawyers for the class. Costs of notice to the class and administration of claims will be borne separately by the Company. The settlement agreement resulted in an after-tax charge of $7 million in the first quarter of 2004.

Guarantees and Surety Bonds

As of December 31, 2004, the Company had issued $16 million of guarantees to support commodity transactions of subsidiaries. The Company had also purchased $11 million of surety bonds for various purposes, including providing worker compensation coverage and obtaining licenses, permits, and rights-of-way. Under the terms of surety bonds, the Company is obligated to indemnify the respective surety bond company for any amounts paid.

Indemnifications

As part of commercial contract negotiations in the normal course of business, the Company may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. The Company is unable to develop an estimate of the maximum potential amount of future payments under these contracts because events that would obligate the Company have not yet occurred or, if any such event has occurred, the Company has not been notified of its occurrence. However, at December 31, 2004, management believes future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on its results of operations, cash flows or financial position.

Stranded Costs

In 1999, Virginia enacted the Virginia Restructuring Act that established a detailed plan to restructure Virginia’s electric utility industry. Under the Virginia Restructuring Act, the generation portion of the Company’s Virginia jurisdictional operations is no longer subject to cost-based regulation. The legislation’s deregulation of generation was an event that required the discontinuance of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, for the Virginia jurisdictional portion of the Company’s generation operations in 1999. In April 2004, the Governor of Virginia signed into law amendments to the Virginia Restructuring Act and the Virginia fuel factor statute. The amend - -

2004 / Page 50

Notes to Consolidated Financial Statements, Continued

ments extend capped base rates by three and one-half years, to December 31, 2010, unless modified or terminated earlier under the Virginia Restructuring Act. In addition to extending capped rates, the amendments:

• Lock in the Company’s fuel factor provisions until the earlier of July 1, 2007 or the termination of capped rates;

• Provide for a one-time adjustment of the Company’s fuel factor, effective July 1, 2007 through December 31, 2010 (unless capped rates are terminated earlier under the Virginia Restructuring Act), with no adjustment for previously incurred over-recovery or under-recovery, thus eliminating deferred fuel accounting for the Virginia jurisdiction; and

• End wires charges on the earlier of July 1, 2007 or the termination of capped rates, consistent with the Virginia Restructuring Act’s original timetable.

Wires charges, also known as competitive transition charges, are permitted to be collected by utilities until July 1, 2007, under the Virginia Restructuring Act. The Company has agreed to forego the collection of wires charges in 2005; and as such, Virginia customers will not pay the fee if they switch from the Company to a different service provider.

The Company believes capped electric retail rates and, where applicable, wires charges provided under the Virginia Restructuring Act provide an opportunity to recover a portion of its potentially stranded costs, depending on market prices of electricity and other factors. Stranded costs are those generation-related costs incurred or commitments made by utilities under cost-based regulation that may not be reasonably expected to be recovered in a competitive market.

In the capped rate environment, the Company remains exposed to numerous risks, including, among others, exposure to potentially stranded costs, future environmental compliance requirements, changes in tax laws, inflation and increased capital costs. At December 31, 2004, the Company’s exposure to potentially stranded costs included: long-term power purchase contracts that could ultimately be determined to be above market; generating plants that could possibly become uneconomic in a deregulated environment; and unfunded obligations for nuclear plant decommissioning and postretirement benefits not yet recognized in the financial statements.

Note 20. Fair Value of Financial Instruments

Substantially all of the Company’s financial instruments are recorded at fair value, with the exception of the instruments described below that are reported based on historical cost. Fair values have been determined using available market information and valuation methodologies considered appropriate by management. The financial instruments’ carrying amounts and fair values as of December 31, 2004 and 2003 were as follows:

	2004				2003
	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
(millions)
Long-term debt	$	4,338	$	4,455	$	4,437	$	4,641
Junior subordinated notes payable to affiliated trust		412		445		412		454
Note payable to parent		220		224		220		222

(1) Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. The carrying amount of debt issues with short-term maturities and variable rates repriced at current market rates is a reasonable estimate of their fair value.

Note 21. Credit Risk

Credit risk is the risk of financial loss to the Company if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, Dominion and its subsidiaries, including the Company, maintain credit policies, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits or may be required to prepay the transaction. Amounts reported as margin deposit liabilities represent funds held by the Company that resulted from various trading counterparties exceeding agreed-upon credit limits established by the Company. Amounts reported as margin deposit assets represent funds held on deposit by various trading counterparties that resulted from the Company exceeding agreed-upon credit limits established by the counterparties. As of December 31, 2004 and 2003, the Company had margin deposit assets (reported in other current assets) of $54 million and $41 million, respectively, and margin deposit liabilities (reported in other current liabilities) of $19 million and $1 million, respectively.

The Company maintains a provision for credit losses based on factors surrounding the credit risk of its customers, historical trends and other information. Management believes, based on the Company’s credit policies and its December 31, 2004 provision for credit losses, that it is unlikely that a material adverse effect on its financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

2004 / Page 51

Notes to Consolidated Financial Statements, Continued

The Company sells electricity and provides distribution and transmission services to a diverse group of customers, including residential, commercial and industrial customers as well as rural electric cooperatives and municipalities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. In addition, the Company enters into contracts with various companies in the energy industry for purchases and sales of energy-related commodities, including natural gas and electricity in its energy trading and risk management activities. These transactions principally occur in the Northeast, Midwest and Mid-Atlantic regions of the United States; however, management does not believe that this geographic concentration contributes significantly to the Company’s overall exposure to credit risk.

The Company’s exposure to credit risk is concentrated primarily within its energy trading and risk management activities, as the Company transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. At December 31, 2004, gross credit exposure related to these transactions totaled $695 million, reflecting the unrealized gains for contracts carried at fair value plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral. After the application of collateral, the Company’s credit exposure totaled $677 million. Of this amount, investment grade counterparties represent 97% and no single counterparty exceeded 10%. The credit exposure amounts exclude amounts receivable from affiliated companies.

Note 22. Related Party Transactions

The Company engages in related party transactions primarily with affiliates (Dominion subsidiaries). The Company’s accounts receivable and payable balances with affiliates are settled based on contractual terms on a monthly basis, depending on the nature of the underlying transactions. The Company is included in Dominion’s consolidated federal income tax return and participates in certain Dominion benefit plans. The significant related party transactions are disclosed below.

Transactions with Affiliates

The Company, through an unregulated subsidiary, transacts with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Through this unregulated subsidiary, the Company is also involved in facilitating Dominion’s enterprise risk management by entering into certain financial derivative commodity contracts with affiliates. These contracts, which are principally comprised of commodity swaps, are used by Dominion subsidiaries to manage commodity price risks associated with purchases and sales of natural gas. As part of Dominion’s enterprise risk management, the Company generally manages such risk exposures by entering into offsetting derivative instruments with third parties. The Company reports both affiliated and third party derivative instruments at fair value, with related changes included in earnings, except to the extent designated as cash flow hedges.

Presented below are affiliated transactions recorded in operating revenue and operating expenses:

	Year Ended December 31,
	2004			2003			2002
(millions)
Purchases of natural gas, gas transportation and storage services from affiliates	$	1,152		$	737		$	162
Sales of natural gas to affiliates		701			673			279
Sales of electricity to affiliates		—			10			1
Net realized gains (losses) on affiliated commodity derivative contracts		(11	)		(11	)		45

The Company’s Consolidated Balance Sheets include derivative assets with affiliates of $84 million and $86 million at December 31, 2004 and 2003, respectively, and derivative liabilities with affiliates of $34 million and $65 million at December 31, 2004 and 2003, respectively.

Dominion Resources Services Inc. (Dominion Services) provides accounting, legal and certain administrative and technical services to the Company. The Company provides certain services to affiliates, including charges for facilities and equipment usage. The cost of these services is as follows:

	Year Ended December 31,
	2004		2003		2002
(millions)
Services provided to the Company by Dominion Services	$	276	$	290	$	267
Services provided by the Company to affiliates		26		27		29

The Company assigned energy contracts to a Dominion subsidiary in 2003, with regulatory approval, in connection with Dominion’s plan to transfer certain wholesale power marketing activities that occur outside of the Company’s service territory. The Company received $13 million representing the net fair value of the contracts transferred. The transferred contracts involve the delivery of electric energy for physical power purchases of 17 million megawatt-hours and sales of 19 million megawatt-hours for 2003 through 2006.

The Company assigned a sales contract to a Dominion subsidiary in 2003, involving the delivery of approximately 6 million megawatt-hours of wholesale electric energy in 2003, declining by approximately 0.5 million megawatt-hours annually from 2004 through 2006 to 4,000 megawatt-hours in 2008.

Transactions with Dominion

The Company leases its principal office building from Dominion under an agreement that expires in 2008. The lease agreement was approved by the Virginia Commission and is accounted for as a capital lease. The capitalized cost of the property under the lease, net of accumulated amortization, was approximately $8 million and $10 million at December 31, 2004 and 2003,

2004 / Page 52

Notes to Consolidated Financial Statements, Continued

respectively. The rental payments for this lease were $3 million each in 2004, 2003 and 2002.

The Company and its subsidiaries have borrowed funds from Dominion. At December 31, 2004 and 2003, outstanding borrowings, net of repayments, under a short-term demand note totaled $645 million and $154 million, respectively, and a long-term note totaled $220 million for both periods. Interest charges incurred by the Company related to these borrowings were $11 million and $1 million in 2004 and 2003, respectively.

In 2004, as approved by the Virginia Commission, Dominion made an equity investment in the Company through the purchase of the Company’s common stock. The Company issued 20,115 shares of its common stock to Dominion for cash consideration of $500 million. The Company used the proceeds in part to pay down its $345 million short-term demand note from Dominion.

In 2004 and 2003, the Company recorded $11 million and $21 million, respectively, of other paid-in capital in connection with the reduction in amounts payable to Dominion.

Other Related Party Transactions

Upon adoption of FIN 46R for its interests in special purpose entities on December 31, 2003, the Company ceased to consolidate the Virginia Power Capital Trust II, a finance subsidiary of the Company. The junior subordinated notes issued by the Company and held by the trust are reported as long-term debt. The Company reported $31 million of interest expense on the junior subordinated notes payable to affiliated trust in 2004 and $30 million of distributions of mandatorily redeemable trust preferred securities in 2003.

Note 23. Operating Segments

The Company is organized primarily on the basis of products and services sold in the United States.

The Company manages its operations through the three operating segments:

Generation includes the Company’s portfolio of electric generating facilities, power purchase agreements, marketing of its excess generation resources and coal trading and marketing activities.

Energy includes the Company’s electric transmission operations and energy trading and risk management activities.

Delivery includes the Company’s electric distribution system and customer service operations.

The Energy segment’s electric transmission operations and the Delivery segment continue to be subject to the requirements of SFAS No. 71.

The majority of the Company’s revenue is provided through tariff rates. Generally, such revenue is allocated among the three segments for management reporting based on an unbundled rate methodology.

In addition, the Company also reports Corporate and Other functions as a segment. The contribution to net income by the Company’s operating segments is determined based on a measure of profit that executive management believes to be representative of the segments’ core earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by executive management in assessing the segment’s performance or allocating resources among the segments. These specific items are reported in the Corporate and Other segment and in 2004 include:

• Charges reflecting the Company’s valuation of its interest in a long-term power tolling contract and the termination of three long-term power purchase agreements;

• A charge related to a class action lawsuit settlement; and

• A benefit to adjust restoration expenses accrued in 2003 associated with Hurricane Isabel.

2003 specific items include:

• Cumulative effect of changes in accounting principles;

• Incremental restoration expenses associated with Hurricane Isabel;

• Charges for the termination of two long-term power purchase agreements and restructuring of certain electric sales contracts; and

• Severance costs for workforce reduction.

The Company reported no specific items in Corporate and Other attributable to its operating segments in 2002.

During the fourth quarter of 2004, the Company performed an evaluation of its Clearinghouse trading and marketing operations, which resulted in a decision to exit certain energy trading activities and instead focus on the optimization of company assets. Beginning in 2005, all revenue and expenses from the Clearinghouse’s optimization of company assets will be reported as part of the results of the business segments operating the related assets, in order to better reflect the performance of the underlying assets. As a result of these changes, 2004 and 2003 results now reflect revenue and expenses associated with the Clearinghouse’s coal trading and marketing activities in the Generation segment.

Intersegment sales and transfers are based on underlying contractual arrangements and agreements and may result in intersegment profit or loss.

2004 / Page 53

Notes to Consolidated Financial Statements, Continued

The following table presents segment information pertaining to the Company’s operations:

	Generation		Energy			Delivery		Corporate and Other			Eliminations			Consolidated Total
(millions)
2004
Operating revenue	$	4,527	$	63		$	1,142	$	10		$	(1	)	$	5,741
Depreciation and amortization		206		34			234		22			—			496
Interest and related charges		128		29			99		1			(3	)		254
Income tax expense (benefit)		235		(69	)		173		(100	)		—			239
Net income (loss)		407		(109	)		288		(155	)		—			431
Capital expenditures		431		117			309		—			—			857
Total assets (at December 31)		9,445		3,555			5,102		—			(784	)		17,318
2003
Operating revenue	$	3,795	$	535		$	1,101	$	10		$	(4	)	$	5,437
Depreciation and amortization		171		32			224		31			—			458
Interest and related charges		144		34			123		4			(3	)		302
Income tax expense (benefit)		245		60			158		(127	)		—			336
Net income (loss)		406		100			282		(227	)		—			561
Capital expenditures		646		87			350		—			—			1,083
Total assets (at December 31)		9,269		3,672			5,106		—			(1,163	)		16,884
2002
Operating revenue	$	3,671	$	246		$	1,048	$	12		$	(5	)	$	4,972
Depreciation and amortization		206		31			224		34			—			495
Interest and related charges		143		34			120		—			(3	)		294
Income tax expense		271		20			132		2			—			425
Net income		486		28			255		4			—			773

Note 24. Quarterly Financial Data (Unaudited)

A summary of the quarterly results of operations for the years ended December 31, 2004 and 2003 follows. Amounts reflect all adjustments, consisting of only normal recurring accruals, necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter			Year
(millions)
2004
Operating revenue	$	1,301	$	1,348	$	1,659	$	1,433		$	5,741
Income (loss) from operations		234		167		466		(14	)		853
Net income (loss)		109		72		259		(9	)		431
Balance available for common stock		105		68		255		(13	)		415
2003
Operating revenue	$	1,511	$	1,215	$	1,518	$	1,193		$	5,437
Income (loss) from operations		552		253		362		(28	)		1,139
Income (loss) before cumulative effect of changes in accounting principles		306		133		200		(57	)		582
Net income (loss)		390		133		200		(162	)		561
Balance available for common stock		387		130		196		(167	)		546

The 2004 results include the impact of the following significant item:

• Fourth quarter results include a $112 million after-tax charge reflecting the Company’s valuation of its interest in a long-term power tolling contract that is subject to a planned divestiture in the first quarter of 2005.

The 2003 results include the impact of the following significant items:

• First quarter results include a $84 million net after-tax gain representing the cumulative effect of adopting SFAS No. 143 and EITF 02-3, as described in Note 3;

2004 / Page 54

Notes to Consolidated Financial Statements, Continued

• Third quarter results include $80 million of after-tax incremental restoration expenses associated with Hurricane Isabel; and

• Fourth quarter results include $105 million after-tax loss representing the cumulative effect of adopting Issue C20 and FIN 46R, as described in Note 3, and $42 million of after-tax incremental restoration expenses associated with Hurricane Isabel.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Senior management, including the Chief Executive Officers and Principal Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, the Chief Executive Officers and Principal Financial Officer have concluded that the Company’s disclosure controls and procedures are effective. There were no changes in the Company’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

On December 31, 2003, the Company adopted FIN 46R for its interests in special purpose entities referred to as SPEs. As a result, the Company has included in its Consolidated Financial Statements the SPE described in Note 3 to the Consolidated Financial Statements. The Consolidated Balance Sheet as of December 31, 2004 reflects $350 million of net property, plant and equipment and deferred charges and $370 million of related debt attributable to the SPE. As the SPE is owned by unrelated parties, the Company does not have the authority to dictate or modify, and therefore cannot assess, the disclosure controls and procedures in place at this entity.

Item 9B. Other Information

None.

2004 / Page 55

Part III

Item 10. Directors and Executive Officers of the Registrant

(a) Information concerning directors of Virginia Electric and Power Company, each of whom is elected annually, is as follows:

Name and Age	Principal Occupation for Last Five Years and Directorships in Public Corporations	Year First Elected as Directors
Thos. E. Capps (69)	Chairman of the Board of Directors and Chief Executive Officer of Dominion from August 2000 to date; Chairman of the Board of Directors of Virginia Electric and Power Company from September 1997 to date; Chairman of the Board of Directors and Chief Executive Officer of Consolidated Natural Gas Company from January 2004 to date; President of Dominion from August 2000 to December 2003; Chief Executive Officer and President of Consolidated Natural Gas Company from January 2000 to December 2003; Vice Chairman of the Board of Directors, President and Chief Executive Officer of Dominion from January 2000 to August 2000. Mr. Capps is also a director of Amerigroup Corporation and Associated Electric and Gas Insurance Services (AEGIS).	1986
Thomas F. Farrell, II (50)	President and Chief Operating Officer of Dominion from January 2004 to date; President and Chief Operating Officer of Consolidated Natural Gas Company from January 2004 to date; Executive Vice President of Dominion from March 1999 to December 2003; President and Chief Executive Officer of Virginia Electric and Power Company from December 2002 to December 2003; Executive Vice President of Consolidated Natural Gas Company from January 2000 to December 2003; Chief Executive Officer of Virginia Electric and Power Company from May 1999 to December 2002.	1999
Thomas N. Chewning (59)	Executive Vice President and Chief Financial Officer of Dominion from May 1999 to date; Executive Vice President and Chief Financial Officer of Consolidated Natural Gas Company from January 2000 to date.	1999

Audit Committee Financial Expert

The Company is a wholly-owned subsidiary of Dominion Resources, Inc. As permitted by SEC rules, its Board of Directors serves as the Company’s audit committee and is comprised entirely of executive officers of the Company. The Board of Directors has determined that all of its audit committee members, Thos. E. Capps, Thomas F. Farrell, II and Thomas N. Chewning, are audit committee financial experts as defined by the SEC and, as executive officers of the Company, are not deemed independent.

(b) Information concerning the executive officers of Virginia Electric and Power Company, each of whom is elected annually is as follows:

Name and Age	Business Experience Past Five Years
Jay L. Johnson (58)	Executive Vice President of Dominion and President and Chief Executive Officer of Virginia Electric and Power Company from December 2002 to date; Senior Vice President, Business Excellence, Dominion Energy, Inc. from September 2000 to December 2002; Chief of Naval Operations, U.S. Navy, and member of the Joint Chiefs of Staff from 1996 until July 2000.
Paul D. Koonce (45)	Chief Executive Officer—Energy of Virginia Electric and Power Company from January 2004 to date; Chief Executive Officer—Transmission of Virginia Electric and Power Company from January 2003 to December 2003; Senior Vice President—Portfolio Management of Virginia Electric and Power Company from January 2000 to December 2002.
Mark F. McGettrick (47)	President and Chief Executive Officer—Generation of Virginia Electric and Power Company from January 2003 to date; Senior Vice President and Chief Administrative Officer of Dominion from January 2002 to December 2002; President of Dominion Resources Services, Inc. from October 2002 to January 2003; Senior Vice President—Customer Service and Metering of Virginia Electric and Power Company from January 2000 to December 2001.
Gary L. Sypolt (51)	President—Transmission of Virginia Electric and Power Company from January 2003 to date; Senior Vice President—Transmission of Dominion Transmission, Inc., formerly CNG Transmission Corporation, from September 1999 to January 2003.

2004 / Page 56

Name and Age	Business Experience Past Five Years
David A. Christian (50)	Senior Vice President—Nuclear Operations and Chief Nuclear Officer from April 2000 to date; Vice President—Nuclear Operations from July 1998 to April 2000.
G. Scott Hetzer (48)	Senior Vice President and Treasurer of Dominion from May 1999 to date; Senior Vice President and Treasurer of Virginia Electric and Power Company and Consolidated Natural Gas Company from January 2000 to date.
Thomas A. Hyman, Jr. (53)	Senior Vice President—Customer Service and Planning of Virginia Electric and Power Company and Regulated Gas Distribution Companies of Consolidated Natural Gas Company from July 2003 to date; Senior Vice President—Gas Distribution and Customer Services of Virginia Electric and Power Company from January 2002 to July 2003; Senior Vice President—Gas Distribution and Customer Services of Regulated Gas Distribution Companies of Consolidated Natural Gas Company from December 2001 to July 2003; Senior Vice President—Gas Distribution of Regulated Gas Distribution Companies of Consolidated Natural Gas Company from October 2000 to December 2001; Senior Vice President—Electric Distribution of Virginia Electric and Power Company from January 2000 to October 2000
William R. Matthews (57)	Senior Vice President—Nuclear Operations of Virginia Electric and Power Company from July 2002 to date; Vice President—Nuclear Operations of Dominion Energy, Inc. from February 2002 to July 2002; Vice President and Senior Nuclear Executive—Millstone of Dominion Energy, Inc. from May 2001 to February 2002; Vice President—Nuclear Operations of Virginia Electric and Power Company from April 2000 to May 2001; Site Vice President—North Anna of Virginia Electric and Power Company from March 1998 to April 2000.
Edward J. Rivas (60)	Senior Vice President—Fossil & Hydro of Virginia Electric and Power Company from September 1999 to date.
Jimmy D. Staton (44)	Senior Vice President—Operations July 2003 to date; Senior Vice President—Electric Distribution of Virginia Electric and Power Company from January 2003 to July 2003; Senior Vice President—Electric Transmission and Electric Distribution of Virginia Electric and Power Company from December 2001 to January 2003; Senior Vice President—Electric Distribution of Virginia Electric and Power Company from October 2000 to December 2001; Senior Vice President—Gas Distribution and Regulatory of Virginia Electric and Power Company from January 2000 to October 2000.
Steven A. Rogers (43)	Vice President, Controller and Principal Accounting Officer of Dominion and Consolidated Natural Gas Company and Vice President and Principal Accounting Officer of Virginia Electric and Power Company from June 2000 to date; Controller of Virginia Electric and Power Company from January 2000 to May 2000; Controller of Dominion Energy, Inc. from September 1998 to June 2000.

Any service listed for Dominion, Dominion Energy, Inc., Consolidated Natural Gas Company and Dominion Transmission, Inc., reflects services at a parent, subsidiary or affiliate.

There is no family relationship between any of the persons named in response to Item 10.

In May 2004, Dominion sold its telecommunications subsidiary, Dominion Telecom, Inc., to a third party and Dominion Telecom, Inc. became Elantic Telecom, Inc. Subsequent to the sale, Elantic Telecom, Inc. filed for protection under Chapter 11 of the U.S. Federal Bankruptcy code. Messrs. Johnson, Hetzer and Staton served as executive officers of Dominion Telecom, Inc. during the two years prior to its sale.

Code of Ethics

The Company has adopted a Code of Ethics that applies to its principal executive, financial and accounting officers as well as its employees. This Code of Ethics is available on the corporate governance section of Dominion’s website (www.dom.com). You may also request a copy of the Code of Ethics, free of charge, by writing or telephoning the Company at: Corporate Secretary, 120 Tredegar Street, Richmond, Virginia 23219, Telephone (804) 819-2000. Any waivers or changes to the Company’s Code of Ethics will be posted on the Dominion website.

2004 / Page 57

Item 11. Executive Compensation

The Summary Compensation Table below includes compensation paid by the Company for services rendered in 2004, 2003 and 2002 to the Chief Executive Officers and the four other most highly compensated executive officers as determined under the SEC executive compensation disclosure rules.

Summary Compensation Table⁽¹⁾

	Annual Compensation					Long Term Compensation
						Awards		Payouts
Name and Principal Position	Year	Salary(2)	Bonus(3)	Other Annual Compensation		Restricted Stock Awards(6)	Securities Underlying Options/SARs(7)	LTIP Payouts	All Other Compensation(8)
Jay L. Johnson	2004	176,364	—	73,271	(4)	302,955	—	—	61,395
Chief Executive Officer	2003	182,333	145,866	29,884		315,318	—	—	43,674
& President	2002	128,404	120,922	18,903		—	—	—	21,697
Mark F. McGettrick	2004	206,765	—	57,876	(4)	377,034	—	—	55,888
Chief Executive Officer &	2003	172,933	138,346	13,934		317,465	—	—	30,456
President—Generation	2002	115,999	92,799	11,571		29,825	—	—	18,382
Paul D. Koonce	2004	92,154	—	12,247	(5)	164,871	—	—	22,945
Chief Executive Officer—Energy	2003	141,440	113,152	12,021		259,652	—	—	22,561
	2002	130,420	90,783	11,471		—	—	—	17,536
Jimmy D. Staton	2004	148,531	54,930	31,698	(5)	142,760	—	—	51,942
Senior Vice President—Operations	2003	270,400	135,200	32,516		259,386	—	—	53,267
	2002	253,604	126,802	31,717		—	—	—	46,023
Edward J. Rivas	2004	167,210	—	41,292	(5)	188,944	—	—	77,393
Senior Vice President—Fossil & Hydro	2003	198,651	96,604	30,153		224,032	—	—	56,996
	2002	155,980	77,990	24,797		—	—	—	35,637
William R. Matthews	2004	138,528	35,758	8,292	(5)	150,011	—	—	28,688
Senior Vice President—Nuclear Operations	2003	170,832	120,212	5,907		184,631	—	—	25,228
	2002	109,229	79,517	4,306		28,313	17,297	—	9,748
David A. Christian	2004	171,904	—	23,142	(5)	218,610	—	—	46,191
Senior Vice President—	2003	153,919	96,969	12,040		195,359	—	—	26,025
Nuclear Operations & Chief Nuclear Officer	2002	151,410	102,807	12,807		—	—	—	21,268

(1) The executive officers included in this table may perform services for more than one subsidiary of Dominion. Compensation for the individuals listed in the table reflects only that portion which is allocated to the Company for each of the years reported and differences from year to year may reflect changes in allocation levels rather than changes in salary.

(2) Salary—Amounts shown may include vacation sold back to the Company.

(3) No bonuses were earned in 2004 under the Company’s profit sharing plan. The amounts in this column for 2004 represent a one-time cash award to Mr. Staton for additional duties he assumed in 2003-2004, and nuclear outage bonuses earned by Mr. Matthews.

(4) Other Annual Compensation—These amounts include reimbursements for tax liability related to income imputed to the officers under IRS rules for certain travel and business expenses, the loan program subsidy and other costs, and personal use of the corporate aircraft. The tax reimbursement amounts are as follows: Johnson ($40,114); and McGettrick ($34,179). The amounts in this column also include income related to perquisites provided under the programs described under Executive Perquisites and Other Benefits in this Item. Individual amounts that represent more than 25% of the total perquisites included are as follows: Johnson ($21,026 for personal use of the corporate aircraft) and McGettrick ($5,908 vehicle allowance and $11,330 for club perquisite—primarily for initiation fee paid on his behalf in 2004). None of these executive officers had perquisites valued at $50,000 or more in 2002 and 2003, so all amounts showing up for those years are related to tax payments.

(5) None of these executive officers received perquisites or other personal benefits in excess of $50,000 or 10% of their total cash compensation. The amounts listed in these columns are tax reimbursement amounts.

(6) Restricted Stock Awards—The number and value of each executive’s aggregated restricted stock holdings at year-end, based on a December 31, 2004 closing price of $67.74 per share, were as follows:

Officer	Number of Restricted Shares(*)	Value
	(#)	($)
Jay L. Johnson	10,385	703,447
Mark F. McGettrick	12,924	875,456
Paul D. Koonce	5,651	382,823
Jimmy D. Staton	4,806	325,547
Edward J. Rivas	6,361	430,862
William R. Matthews	5,050	342,082
David A. Christian	7,359	498,517

Dividends are paid on restricted shares.

(7) Securities Underlying Options—No options were granted in 2003 and 2004.

(8) All Other Compensation—The amounts listed for 2004 are:

(i) Company matching contributions on Employee Savings Plan accounts for the named executives;

(ii)  a quarterly interest rate subsidy and breakage costs paid under the Executive Stock Purchase and Loan Program;

(iii) a payment to the officer to make whole for lost Company match due to IRS rules applicable to the qualified savings plan; and

(iv)  payments made on behalf of officer for whole life insurance policy.

2004 / Page 58

Officer	Employee Savings Plan Match	Executive Stock Loan Program Interest Subsidy	Employee Savings Plan Match Above IRS Limits	Executive Supplemental Life Insurance
Jay L. Johnson	3,144	33,137	2,147	22,967
Mark F. McGettrick	5,217	36,458	3,054	11,159
Paul D. Koonce	1,711	16,046	1,002	4,187
Jimmy D. Staton	3,378	43,260	1,078	4,226
Edward J. Rivas	5,961	55,829	727	14,876
William R. Matthews	4,733	11,218	808	11,929
David A. Christian	4,311	30,845	2,565	8,471

Aggregated Option/SAR Exercises in Last Fiscal Year⁽¹⁾

And FY-End Option/SAR Values

			Number of Securities Underlying Unexercised Options/SARs At FY-End		Value of Unexercised In-the- Money Options/SARs At FY-End(3)
	Shares Acquired on Exercise	Value Realized(2)	Exercisable	Unexercisable	Exercisable	Unexercisable
	(#)	($)	(#)	(#)	($)	($)
Jay L. Johnson	22,237	263,733	34,080	17,040	265,140	132,574
Mark F. McGettrick	30,164	651,177	42,413	21,207	329,972	164,991
Paul D. Koonce	9,035	186,775	37,094	18,546	288,588	144,291
Jimmy D. Staton	8,789	138,579	36,620	18,310	284,900	142,455
Edward J. Rivas	38,075	679,302	48,466	24,234	377,067	188,539
William R. Matthews	18,101	376,940	35,915	17,957	210,280	105,140
David A. Christian	24,056	480,407	70,094	35,046	545,329	272,660

(1) The executive officers included in this table may perform services for more than one subsidiary of Dominion. Options and shares acquired on exercise for individuals listed in the table reflect only that portion which is allocated to the Company. These option exercises were made in connection with the prepayment of executive loans under the Stock Purchase and Loan Program, with the proceeds referred to above being used first (and in most cases exclusively) to pay down the principal of such loans and related taxes.

(2) Spread between the market value at exercise minus the exercise price.

(3) Spread between the market value at year-end minus the exercise price. Year-end stock price was $67.74 per share.

Executive Compensation

The Company’s executive compensation program is regularly reviewed by the Organization, Compensation and Nominating Committee of the Dominion Board (Dominion’s Committee) and its recommendations are subsequently referred to the Company’s Board of Directors. Dominion’s Committee acts independently of management and works with a nationally recognized independent consultant. Dominion’s executive compensation program is designed to provide its executives with competitive salaries, bonuses, long-term incentives and benefits that align their financial success to the financial success of its shareholders and the Company.

This strategy includes placing a substantial portion of executives’ pay at risk, including tying compensation to the achievement of strategic financial performance measures—paying for performance. The Dominion Committee also ensures that Dominion maintains a balanced program to provide the appropriate mix of base salary and annual and long-term incentives.

The 2004 program focused on long-term compensation and annual incentives. The Dominion Committee also permitted and encouraged voluntary prepayments of loans under its grandfathered stock purchase program, reimbursing officers for the additional interest and other costs incurred as a result of any prepayments.

Base Salary and Annual Incentive

The Company targets base pay and annual incentive pay at or slightly above market median for similar positions at companies in our executive labor market. Generally, officers did not receive base salary increases in 2004 (other than for promotions or compelling market reasons). Instead, the Dominion Committee focused on long-term awards.

Under the annual incentive program, “target awards” are established for each executive officer. These target awards are expressed as a percentage of the individual executive’s base salary (for example, 40% x base salary). The target award is the amount of cash that will be paid at year-end if the executive achieves 100% of the goals established at the beginning of the year. A “threshold”—or minimum acceptable level of corporate financial performance—is established, and if this threshold is not met, no executive receives an annual incentive payment. Actual bonuses, if any, are based on a pre-established formula and may exceed 100% of the target award if performance expectations are exceeded. Because Dominion did not achieve the threshold target for 2004, no bonuses were paid under the annual incentive program.

Long-term Incentives

Equity compensation continues to be viewed as the strongest form of long-term incentive as it helps to underscore an individual’s

2004 / Page 59

commitment to the Company while still rewarding performance. During 2004, performance-accelerated restricted stock was the only method used to grant equity to executives. All shares were granted at 100% of the fair market value of Dominion’s stock price on the date of grant.

Stock Ownership Guidelines

Since 2000, Dominion has had ownership guidelines for management in order to emphasize the importance of aligning the interests of management and Dominion shareholders. The Company provides tools to assist management in obtaining their desired ownership levels.

Dominion Resources, Inc.

Stock Ownership Guidelines

Position	Multiple of Salary/ No. of Shares
CEO/COO-Operating Companies	5x / 35,000
Senior Vice President	4x / 20,000
Vice President	3x / 10,000

Retirement Plans

The table below shows the estimated annual straight life benefit that the Company would pay to an employee at normal retirement (age 65) under the benefit formula of the Pension Plan.

2004 Estimated Annual Benefits Payable Upon Retirement Plan

	Credited Years of Service
Final Average Earnings	15		20		25		30
$185,000	$	49,930	$	66,540	$	83,150	$	99,760
$200,000		54,480		72,610		90,740		108,880
$250,000		69,620		92,820		116,030		139,220
$300,000		84,760		113,040		141,310		169,580
$350,000		99,890		133,240		166,580		199,940
$400,000		115,030		153,460		191,880		230,320

Benefits under the Pension Plan are based on:

• highest average base salary over a five consecutive year period during the ten years preceding retirement;

• years of credited service;

• age at retirement; and

• the offset of Social Security benefits.

The Company provides a Special Retirement Account (SRA) feature to the Pension Plan. This account is credited with two-percent of an employee’s base salary earned each year. Account balances are credited with earnings based on the 30-year Treasury rate and may be taken as a lump sum or an annuity at retirement. The above table includes the effect of SRA balances converted to an annual annuity.

In addition, Mr. Johnson will receive 20 years of credited service after 10 years of continuous employment. Mr. McGettrick will receive 5 years of additional age and service if he serves as an officer until his 50th birthday. Mr. Matthews will receive 30 years of credited service if he serves as an officer until age 60. Mr. Rivas is being provided with 30 years of credited service since he has reached the age of 60. Each of the named executives in the Summary Compensation Table, except for Messrs. Johnson and Koonce, will have 30 years of credited service at age 60. Mr. Staton will have 30 years of credited service at age 60 ¹/2.

Benefit Restoration Plan

The Internal Revenue Code imposes certain limits related to Pension Plan benefits. Any resulting reduction in an executive’s Pension Plan benefit will be compensated for under the Restoration Plan.

This Plan was frozen as of December 31, 2004 and the New Benefit Restoration Plan was implemented on January 1, 2005. There was no change in the amount of benefits as a result of this change.

Executive Supplemental Retirement Plan

The Supplemental Plan provides an annual retirement benefit equal to 25% of a participant’s final cash compensation (base pay plus target annual incentive). To retire with full benefits under the Supplemental Plan, an executive must be 55 years old and have been employed by the Company for at least five years. Benefits under the plan are provided either as a lump sum cash payment at retirement or as a monthly annuity typically paid over 10 years. Under this program, Mr. Christian and Mr. Matthews will receive a lifetime benefit if they serve as an officer until age 60 and Koonce will receive a lifetime benefit if he serves as an officer until age 50. Based on 2004 cash compensation, the estimated annual benefit under this plan for executives named in the Summary Compensation Table are: Mr. Johnson—$79,364; Mr. McGettrick—$93,044; Mr. Koonce—$40,687; Mr. Staton—$55,699; Mr. Rivas—$62,704; Mr. Matthews—$51,948; Mr. Christian—$73,059.

This Plan was frozen as of December 31, 2004 and the New Executive Supplemental Retirement Plan was implemented on January 1, 2005. There was no change in the amount of benefits as a result of this change.

Other Executive Agreements and Arrangements

Companies that are in a rapidly changing industry such as ours require the expertise and loyalty of exceptional executives. Not only is the business itself competitive, but so is the demand for such executives. In order to secure the continued services and focus of key management executives, the Company has entered into certain agreements with them, including those named in the Summary Compensation Table.

In 2004, Mr. Rivas entered into a letter agreement with the company, agreeing to postpone his retirement until April 1, 2005 in consideration for a lump sum cash payment at retirement equal to the value of his 2004 performance-accelerated restricted stock award. Mr. Rivas agreed to forgo any long-term awards in 2005.

Mr. Christian and Mr. Matthews have entered into Supplemental Agreements with Dominion whereby they have also agreed not to compete with the activities of Dominion nor solicit any Dominion employees in consideration of their receipt of enhanced benefits under the Supplemental Retirement Plans described above.

2004 / Page 60

Special Arrangements

Executives named in the Summary Compensation Table have entered into employment continuity agreements, which provide benefits in the event of a change in control. Each agreement has a three-year term and is automatically extended for an additional year, unless cancelled by the Company.

The agreements provide for the continuation of salary and benefits for a maximum period of three years after either (1) a change in control, (2) termination without cause following a change in control, or (3) a reduction of responsibilities, salary and incentives following a change in control (if the executive gives 60 days notice). Under the agreements executives would receive the following: (1) an annual base salary not less than the executives’ highest annual base salary during the twelve months preceding the change of control, (2) an annual bonus not less than the highest maximum annual bonus available to the executives during the three years preceding the change of control and (3) continued eligibility for awards under company incentive, savings and benefit plans provided to senior management. In addition, any outstanding stock options and other forms of stock awards will fully vest upon a change in control. Upon a covered executive’s death or disability, or in the event the executive is terminated without cause, the agreement provides for a lump sum severance payment equal to three times base salary plus annual bonus, together with the full vesting of benefits under the company’s benefit plans. If a covered executive is terminated without cause, the executive also will receive full vesting of any outstanding stock options and five years of additional credit for age and service. The agreements indemnify the executives for potential penalties related to the Internal Revenue Code and fees associated with the enforcement of the agreements. If an executive is terminated for cause, the agreements are not effective.

For purposes of the continuity agreements described above, a change of control shall be deemed to have occurred if (i) any person or group becomes a beneficial owner of 20% or more of the combined voting power of Dominion voting stock or (ii) as a direct or indirect result of, or in connection with, a cash tender or exchange offer, a merger or other business combination, a sale of assets, or contested election, the Directors constituting the Dominion Board before any such transactions cease to represent a majority of Dominion or its successor’s Board within two years after the last of such transactions.

Executive Stock Purchase Programs

At the end of 1999, Dominion’s Board approved target levels of stock ownership for executives. The Board also approved a Stock Purchase and Loan Program intended to encourage and facilitate executives’ ownership of common stock through the availability of loans guaranteed by Dominion. Officers borrowed money from an independent bank to purchase stock for which they are personally liable and which Dominion has guaranteed. Because of new restrictions on company loans or guarantees to executives under the Sarbanes-Oxley Act of 2002, Dominion has ceased its programs involving the company guaranty of a third party loan to executives for the purpose of acquiring company stock. In the fall of 2003, the OCN Committee authorized executives with loans to exercise previously granted options or to sell shares of Dominion stock solely for the purpose of paying off their loans under the programs. Every officer of the Company that had a loan outstanding prepaid their loan in 2004, exercising options and selling shares to the extent necessary to pay off the loan balance and cover any resulting tax liability.

During 2001, the stock ownership guidelines for executives were reconfirmed and the Executive Stock Purchase Tool Kit was implemented. The Tool Kit consists of a variety of programs to encourage ownership of Dominion stock by executives who could not participate in the Executive Stock Purchase and Loan programs. Executives who participate in one or more of the Tool Kit programs to achieve their stock ownership target levels receive “bonus shares” for up to twenty-five percent of the value of their investments in Dominion stock. The Tool Kit previously included the availability of loans guaranteed by Dominion, but this alternative has been omitted for the reasons discussed above.

Perquisites and Other Benefits

The Company offers a limited number of perquisites to its executives: company car allowance, a financial planning allowance and a club membership benefit. Furthermore, certain senior and nuclear executives are provided with security systems at their home residence. While the Company does not consider this service to be a perquisite, but instead views its security program as serving a business need for a limited number of executives, the Company will begin counting these costs in its calculation of perquisites for 2004 or until further guidance is offered by the SEC.

Similarly, the Company provides its executives with up to $1,000 in reimbursements for annual physical exams expenses that may not be covered otherwise. The Company does not consider this benefit to be a perquisite and amounts relating to it are not included in the Summary Compensation Table. Finally, as disclosed in Footnote 4 to the Summary Compensation Table, in limited circumstances the Company executives may have use of the company planes for personal travel.

Compensation of Directors

All of the Directors, who are officers of the Company or Dominion, do not receive any compensation for services they provide as directors.

2004 / Page 61

Item 12. Security Ownership Of Certain Beneficial Owners And Management

The table below sets forth as of February 18, 2005, except as noted, the number of shares of Dominion common stock owned by Directors and the executive officers named on the Summary Compensation Table.

	Beneficial Share Ownership
Name	Shares	Restricted Shares	Exercisable Stock Options	Total	Deferred Cash Compensation(1)
Thos. E. Capps(2)	347,776	136,017	1,200,000	1,683,793	—
Thomas N. Chewning	113,987	57,410	450,000	621,397	179
Thomas F. Farrell, II(2)	128,428	86,726	600,000	815,154	—
Jay L. Johnson	9,319	20,314	100,000	129,633	4,487
Mark F. McGettrick	25,060	20,314	100,000	145,374	5,405
Paul D. Koonce	17,579	20,314	166,666	204,559	5,897
Jimmy D. Staton	5,445	8,749	66,667	80,861	11,896
Edward J. Rivas	28,121	8,749	66,667	103,537	4,423
William R. Matthews	16,455	8,749	33,333	58,537	3,710
David A. Christian	23,184	13,999	—	37,183	—
All directors and executive officers as a group (14 persons)(3)	784,403	418,221	3,063,334	4,265,958	47,792

(1) Amounts in this column represent share equivalents and do not have voting rights. At a director’s or executive’s election, cash compensation is deferred until a specified age, future date or retirement and will be distributed in cash.

(2) Messrs. Capps and Farrell disclaim ownership for 18,619 and 399 shares, respectively.

(3) All directors and executive officers as a group own less than 2 percent of the number of Dominion common shares outstanding at February 18, 2005. No individual executive officer or director owns more than one percent of the shares outstanding.

Item 13. Certain Relationships and Related Transactions

See Item 11. Executive Compensation—Executive Stock Purchase Programs, for information concerning certain transactions with executive officers under the Executive Stock Purchase and Loan Programs.

Item 14. Principal Accountant Fees and Services

The following table presents fees paid to Deloitte & Touche LLP for the fiscal years ended December 31, 2004 and 2003.

Type of Fees	2004		2003
(thousands)
Audit fees	$	849	$	854
Audit-related		259		138
Tax fees		700		—
All other fees		—		—
	$	1,808	$	992

Audit Fees are for the audit and review of the Company’s financial statements in accordance with generally accepted auditing standards, including comfort letters, statutory and regulatory audits, consents and services related to SEC matters.

Audit-Related Fees are for assurance and related services that are related to the audit or review of the Company’s financial statements, including employee benefit plan audits, due diligence services and financial accounting and reporting consultation.

Tax Fees reflect the settlement of outstanding arrangements related to tax planning assistance.

In 2003, the Board adopted a pre-approval policy for Deloitte & Touche services and fees. Attached to the policy is a schedule that details the services to be provided and an estimated range of fees to be charged for such services. In December 2004 and January 2005, Dominion’s Audit Committee approved the services and fees for 2005.

2004 / Page 62

Part IV

Item 15. Exhibits and Financial Statement Schedules

(a) Certain documents are filed as part of this Form 10-K and are incorporated by reference and found on the pages noted.

1. Financial Statements

    See Index on page 28.

All schedules are omitted because they are not applicable, or the required information is either not material or is shown in the financial statements or the related notes.

2. Exhibits

3.1	Restated Articles of Incorporation, as in effect on October 28, 2003 (Exhibit 3.1, Form 10-Q for the quarter ended September 30, 2003, File No. 1-2255, incorporated by reference).
3.2	Bylaws, as amended, as in effect on April 28, 2000 (Exhibit 3, Form 10-Q for the period ended March 31, 2000, File No. 1-2255, incorporated by reference).
4.1	See Exhibit 3.1 above.
4.2	Indenture of Mortgage of Virginia Electric and Power Company, dated November 1, 1935, as supplemented and modified by fifty-eight Supplemental Indentures (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255, incorporated by reference); Sixty-Seventh Supplemental Indenture (Exhibit 4(i), Form 8-K, dated April 2, 1991, File No. 1-2255, incorporated by reference); Seventieth Supplemental Indenture, (Exhibit 4(iii), Form 8-K, dated February 25, 1992, File No. 1-2255, incorporated by reference); Seventy-First Supplemental Indenture (Exhibit 4(i)) and Seventy-Second Supplemental Indenture, (Exhibit 4(ii), Form 8-K, dated July 7, 1992, File No. 1-2255, incorporated by reference); Seventy-Third Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated August 6, 1992, File No. 1-2255, incorporated by reference); Seventy-Fourth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated February 10, 1993, File No. 1-2255, incorporated by reference); Seventy-Fifth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated April 6, 1993, File No. 1-2255, incorporated by reference); Seventy-Sixth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated April 21, 1993, File No. 1-2255, incorporated by reference); Seventy-Seventh Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated June 8, 1993, File No. 1-2255, incorporated by reference); Seventy-Eighth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated August 10, 1993, File No. 1-2255, incorporated by reference); Seventy-Ninth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated August 10, 1993, File No. 1-2255, incorporated by reference); Eightieth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated October 12, 1993, File No. 1-2255, incorporated by reference); Eighty-First Supplemental Indenture, (Exhibit 4(iii), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference); Eighty-Second Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated January 18, 1994, File No. 1-2255, incorporated by reference); Eighty-Third Supplemental Indenture (Exhibit 4(i), Form 8-K, dated October 19, 1994, File No. 1-2255, incorporated by reference); Eighty-Fourth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated March 23, 1995, File No. 1-2255, incorporated by reference); and Eighty-Fifth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated February 20, 1997, File No. 1-2255, incorporated by reference).
4.3	Indenture, dated as of June 1, 1986, between Virginia Electric and Power Company and JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Chemical Bank) (Exhibit 4(v), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference).
4.4	Indenture, dated April 1, 1988, between Virginia Electric and Power Company and JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Chemical Bank), as supplemented and modified by a First Supplemental Indenture, dated August 1, 1989, (Exhibit 4(vi), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference); Second Supplemental Indenture, dated May 1, 1999 (Exhibit 4.2, Form S-3, File No. 333-7615, as filed on April 13, 1999, incorporated by reference).
4.5	Subordinated Note Indenture, dated as of August 1, 1995 between Virginia Electric and Power Company and JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Chemical Bank), as Trustee (Exhibit 4(a), Form S-3 Registration Statement File No. 333-20561 as filed on January 28, 1997, incorporated by reference), Form of Second Supplemental Indenture (Exhibit 4.6, Form 8-K filed August 20, 2002, No. 1-2255, incorporated by reference).
4.6	Form of Senior Indenture, dated as of June 1, 1998, between Virginia Electric and Power Company and JP Morgan Chase Bank (formerly The Chase Manhattan Bank) as supplemented by the First Supplemental Indenture (Exhibit 4.2, Form 8-K, dated June 12, 1998, File No. 1-2255, incorporated by reference); Second Supplemental Indenture (Exhibit 4.2, Form 8-K, dated June 3, 1999, File No.1-2255, incorporated by reference); Third Supplemental Indenture (Exhibit 4.2, Form 8-K, dated October 27, 1999, File No. 1-2255,
	incorporated by reference); Form of Fourth Supplemental Indenture (Exhibit 4.2, Form 8-K, dated March 22, 2001, File No. 1-2255, incorporated by reference); and Form of Fifth Supplemental Indenture (Exhibit 4.3, Form 8-K, dated March 22, 2001, File No. 1-2255, incorporated by reference); Form of Sixth Supplemental Indenture (Exhibit 4.2, Form 8-K, dated January 24, 2002, incorporated by reference); Seventh Supplemental Indenture dated September 1, 2002 (Exhibit 4.4, Form 8-K filed September 11, 2002, File No. 1-2255, incorporated by reference); Form of Ninth Supplemental Indenture (Exhibit 4.2, Form 8-K filed December 4, 2003, File No. 1-2255, incorporated by reference); Form of Eighth Supplemental Indenture (Exhibit 4.2, Form 8-K filed February 27, 2003, File No. 1-

2004 / Page 63

	2255, incorporated by reference); Form of Tenth Supplemental Indenture (Exhibit 4.3, Form 8-K filed December 4, 2003, File No. 1-2255, incorporated by reference); Form of Eleventh Supplemental Indenture (Exhibit 4.2, Form 8-K filed December 11, 2003, File No. 1-2255, incorporated by reference).
4.15	Virginia Electric and Power Company agrees to furnish to the Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of Dominion Resources, Inc.’s total consolidated assets.
10.1	Amended and Restated Interconnection and Operating Agreement, dated as of July 29, 1997 between Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit 10(v), Form 10-K for the fiscal year ended December 31, 1997, File No. 1-8489, incorporated by reference).
10.2	Services Agreement between Dominion Resources Services, Inc. and Virginia Electric and Power Company dated January 1, 2000 (Exhibit 10.19, Form 10-K for the fiscal year ended December 31, 1999, File No. 1-2255, incorporated by reference).
10.3	PJM South Implementation Agreement between Virginia Electric and Power Company and PJM Interconnection, L.L.C., dated September 30, 2002, as amended December 6, 2002 (Exhibit 10.4, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-2255, incorporated by reference).
10.4	$1,250,000,000 364-Day Credit Agreement among Dominion Resources, Inc., Virginia Electric and Power Company, Consolidated Natural Gas Company and JPMorgan Chase Bank, as Administrative Agent for the Lenders, dated as of May 29, 2003 (Exhibit 10.1, Form 10-Q for the quarter ended September 30, 2003, File No. 1-2255, incorporated by reference).
10.5	$750,000,000 Three-Year Credit Agreement among Dominion Resources, Inc., Virginia Electric and Power Company, Consolidated Natural Gas Company and JPMorgan Chase Bank, as Administrative Agent for the Lenders, dated as of May 30, 2002 (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2003, File No. 1-8489, incorporated by reference).
10.6	Form of Settlement Agreement in the form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West Virginia and Dominion (Exhibit 10, Form 10-Q for the quarter ended March 31, 2003, File No. 1-2255, incorporated by reference.
10.7*	Dominion Resources, Inc. Executive Supplemental Retirement Plan, as amended and restated effective December 17, 2004 (Exhibit 10.5, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).
10.8*	Dominion Resources, Inc.’s Cash Incentive Plan as adopted December 20, 1991 (Exhibit 10(xxv), Form 10-K for the fiscal year ended December 31, 1991, File No. 1-2255, incorporated by reference).
10.9*	Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, 1997, as amended and restated effective July 20, 2001 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2001, File No. 1-2255, incorporated by reference).
10.10*	Dominion Resources, Inc. Executive Stock Purchase and Loan Plan II, dated February 15, 2000 (Exhibit 10.10, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-2255, incorporated by reference).
10.11*	Form of Employment Continuity Agreement for certain officers of the Company, amended and restated July 15, 2003 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2003, File No. 1-2255, incorporated by reference).
10.12*	Dominion Resources, Inc. Retirement Benefit Funding Plan, effective June 29, 1990 as amended and restated September 1, 1996 (Exhibit 10(iii), Form 10-Q for the quarter ended June 30, 1997, File No. 1-8489, incorporated by reference).
10.13*	Dominion Resources, Inc. Retirement Benefit Restoration Plan, as amended and restated effective December 17, 2004 (Exhibit 10.6, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).
10.14*	Dominion Resources, Inc. Executives’ Deferred Compensation Plan, amended and restated effective December 17, 2004 (Exhibit 10.7, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).
10.15*	Dominion Resources, Inc. New Executive Supplemental Retirement Plan, effective January 1, 2005 (Exhibit 10.8, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).
10.16*	Dominion Resources, Inc. New Retirement Benefit Restoration Plan, effective January 1, 2005 (Exhibit 10.9, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).
10.17*	Dominion Resources, Inc. New Deferred Compensation Plan, effective January 1, 2005 (Exhibit 10.10, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).
10.18*	Dominion Resources, Inc. Leadership Stock Option Plan, effective July 1, 2000, as amended and restated effective July 20, 2001 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2001, File No. 1-2255, incorporated by reference).
10.19*	Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated December 17, 2004 (Exhibit 10.11, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).
10.20*	Dominion Resources, Inc. Security Option Plan, effective January 1, 2003, amended December 31, 2004 and restated effective January 1, 2005 (Exhibit 10.13, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).

2004 / Page 64

10.21*	Letter agreement dated February 27, 2003 between Dominion and Thomas F. Farrell, II (Exhibit 10.24, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).
10.22*	Employment Agreement dated August 1, 2000 between the Company and Jimmy D. Staton (Exhibit 10.24, Form 10-K for the fiscal year ended December 31, 2001, File No. 1-2255, incorporated by reference).
10.23*	Supplemental Retirement Agreement dated December 12, 2000, between the Company and David A. Christian (Exhibit 10.25, Form 10-K for the fiscal year ended December 31, 2001, File No. 1-2255, incorporated by reference).
10.24*	Offer of employment dated August 21, 2000 between Dominion Energy, Inc. and Jay L. Johnson (Exhibit 10.26, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-2255, incorporated by reference).
10.25*	Employment agreement dated August 1, 1999 between the Company and Mark F. McGettrick (Exhibit 10.20, Form 10-K for the fiscal year ended December 31, 2000, File No. 1-2255, incorporated by reference).
10.26*	Supplemental retirement agreement dated December 20, 2002 between Dominion and William R. Matthews (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2004, File No. 1-2255, incorporated by reference).
10.27*	Supplemental retirement agreement dated October 22, 2002 between Dominion and Paul D. Koonce (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2004, File No. 1-2255, incorporated by reference).
10.28*	Supplemental retirement agreement dated July 29, 2002 between Dominion Resources Services, Inc. and Edward J. Rivas (Exhibit 10.27, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-2255, incorporated by reference).
10.29*	Retirement agreement dated March 30, 2004 between the Company and Mr. Edward J. Rivas (filed herewith)
10.30*	Supplemental award related to increased responsibilities dated July 20, 2004 between the Company and Jimmy D. Staton (filed herewith).
12.1	Ratio of earnings to fixed charges (filed herewith).
12.2	Ratio of earnings to fixed charges and dividends (filed herewith).
21	Subsidiaries of the Registrant (filed herewith).
23.1	Consent of Deloitte & Touche LLP (filed herewith).
23.2	Consent of Jackson & Kelly (filed herewith).
23.3	Consent of McGuire Woods LLP (filed herewith).
31.1	Certification by Registrant’s Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
31.2	Certification by Registrant’s Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
31.3	Certification by Registrant’s Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
31.4	Certification by Registrant’s Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
32	Certification to the Securities and Exchange Commission by Registrant’s Chief Executive Officers and Chief Financial Officer, as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).

* Indicates management contract or compensatory plan or arrangement.

2004 / Page 65

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

VIRGINIA ELECTRIC AND POWER COMPANY
By:	/s/    THOS. E. CAPPS
	(Thos. E. Capps, Chairman of the Board of Directors)

Date: February 28, 2005

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 28th day of February, 2005.

Signature	Title
/s/    THOS. E. CAPPS         Thos. E. Capps	Chairman of the Board of Directors
/s/    THOMAS N. CHEWNING         Thomas N. Chewning	Director
/s/    THOMAS F. FARRELL, II         Thomas F. Farrell, II	Director
/s/    JAY L. JOHNSON         Jay L. Johnson	President and Chief Executive Officer
/s/    PAUL D. KOONCE         Paul D. Koonce	Chief Executive Officer—Energy
/s/    MARK F. MCGETTRICK         Mark F. McGettrick	President and Chief Executive Officer—Generation
/s/    G. SCOTT HETZER         G. Scott Hetzer	Senior Vice President and Treasurer (Principal Financial Officer)
/s/    STEVEN A. ROGERS         Steven A. Rogers	Vice President (Principal Accounting Officer)

2004 / Page 66

EX-10.29

Exhibit 10.29

March 30, 2004

Mr. Ed Rivas

5700 Rockport Landing Place

Midlothian, VA 23113

Dear Ed:

In consideration for your agreement to postpone your retirement from the Company until April 1, 2005, the Company will provide you with the following benefits in addition to any qualified or non-qualified plan benefits you have earned as of that date:

1. You will receive a cash payment of $260,000 as of your retirement date. This payment will be paid in your April 2005 paycheck and is contingent on your retirement date being no earlier than April 1, 2005. It is also in consideration of your agreement to forgo any long-term compensation that may be awarded to officers in 2005.

2. You will receive your company car as a gift as of your retirement date. This will be a taxable gift.

3. The forfeiture provision of your 2001 stock options will be waived as of June 1, 2004, allowing you to begin diversifying your stock holdings without forfeiting your 2001 stock options. As you know, all sales must be in compliance with the company’s insider trading policy.

4. Your 2005 bonus will be prorated based on the number of completed months of service in 2005 and will be paid as a lump sum in your final paycheck.

You will have the option of choosing to defer items 1 and 4 above into the deferred compensation plan. If you accept these terms, please execute two originals of this document below and return one to me.

/s/ Mark F. McGettrick

Mark F. McGettrick

President and Chief Executive Officer

AGREED AND ACCEPTED:

/s Edward Rivas	04/06/04
Edward J. Rivas	Date

EX-10.30

Exhibit 10.30

M E M O R A N D U M

TO: Mr. Thomas F. Farrell	Executive Compensation
FROM: Jay L. Johnson	July 20, 2004

Award for

Jimmy D. Staton

In recognition of his efforts and additional responsibilities assumed during the DTSI transition, I propose that we give Jimmy Staton an award of $100,000. Effective August 1^st, 95% of this award will be paid directly into the Dominion Deferred Compensation Plan and will be subject to the terms and conditions of that plan. It shall be invested in the Dominion stock fund with the expectation that it will remain invested in that fund for the duration of Jimmy’s tenure as an officer. The remainder of the award will be paid to Jimmy through payroll in his August paycheck, allowing for any necessary taxes to be withheld as a result of this bonus.

/s/ Jay L. Johnson

Jay L. Johnson

Approved:	/s/ Thomas. F. Farrell
	Thomas F. Farrell

EX-12.1

Exhibit 12.1

Virginia Electric and Power Company

Computation of Ratio of Earnings to Fixed Charges

(millions of dollars)

	Years Ended
	2004		2003		2002		2001		2000		1999
Earnings, as defined:
Earnings before income taxes and minority interests in consolidated subsidiaries	$	670	$	919	$	1,198	$	733	$	837	$	743
Fixed charges included in the determination of net income		266		311		304		310		303		297
Total earnings, as defined	$	936	$	1,230	$	1,502	$	1,043	$	1,140	$	1,040
Fixed charges, as defined:
Interest charges	$	262	$	320	$	311	$	320	$	297	$	290
Rental interest factor		11		10		10		10		6		7
Total fixed charges, as defined	$	273	$	330	$	321	$	330	$	303	$	297
Ratio of Earnings to Fixed Charges		3.43		3.73		4.68		3.16		3.76		3.50

EX-12.2

Exhibit 12.2

Virginia Electric and Power Company

Computation of Ratio of Earnings to Fixed Charges and Preferred Dividends

(millions of dollars)

	Years Ended
	2004		2003		2002		2001		2000		1999
Earnings, as defined:
Earnings before income taxes and minority interests in consolidated subsidiaries	$	670	$	919	$	1,198	$	733	$	837	$	743
Fixed charges included in the determination of net income		266		311		304		310		303		297
Total earnings, as defined	$	936	$	1,230	$	1,502	$	1,043	$	1,140	$	1,040
Fixed charges, as defined:
Interest charges	$	262	$	320	$	311	$	320	$	297	$	290
Preference security dividend requirements of consolidated subsidiaries		25		25		25		38		54		57
Rental interest factor		11		10		10		10		6		7
Total fixed charges, as defined	$	298	$	355	$	346	$	368	$	357	$	354
Ratio of Earnings to Fixed Charges and Preferred Dividends		3.14		3.47		4.34		2.83		3.19		2.94

EX-21

Exhibit 21

Virginia Electric and Power Company

Subsidiaries of the Registrant

As of December 31, 2004

Name	Jurisdiction of Incorporation	Name Under Which Business is Conducted
Virginia Electric and Power Company	Virginia	Dominion Virginia Power (in Virginia) Dominion North Carolina Power (in North Carolina)
Virginia Power Capital Trust II	Delaware	Virginia Power Capital Trust II
Virginia Power Fuel Corporation	Virginia	Virginia Power Fuel Corporation
Virginia Power Services, Inc.	Virginia	Virginia Power Services, Inc.
Dominion Generation Corporation	Virginia	Dominion Generation Corporation
Virginia Power Energy Marketing, Inc.	Virginia	Virginia Power Energy Marketing, Inc.
Virginia Power Services Energy Corp., Inc.	Virginia	Virginia Power Services Energy Corp., Inc.
Virginia Power Nuclear Services Company	Virginia	Virginia Power Nuclear Services Company
VP Property, Inc.	Virginia	VP Property, Inc.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-38510 and 333-96973 on Forms S-3 of our report dated February 28, 2005, (which report expressed an unqualified opinion and included an explanatory paragraph as to changes in accounting principles in 2003 for: asset retirement obligations, contracts involved in energy trading, derivative contracts not held for trading purposes, derivative contracts with a price adjustment feature, the consolidation of variable interest entities, and guarantees), relating to the consolidated financial statements of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Resources, Inc.), appearing in the Annual Report on Form 10-K of Virginia Electric and Power Company for the year ended December 31, 2004.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 28, 2005

EX-23.2

Exhibit 23.2

February 28, 2005

Virginia Electric and Power Company

One James River Plaza

701 East Cary Street

Richmond, Virginia 23219

Re: Form 10-K for the Fiscal Year Ended December 31, 2004

Ladies and Gentlemen:

We consent to the incorporation by reference into the Registration Statements of Virginia Electric and Power Company on Form S-3 File Nos. 333-38510 and 333-96973 of the statements included in this Annual Report on Form 10-K for the fiscal year ended December 31, 2004, made in regard to our Firm that are governed by the laws of West Virginia and that relate to legal conclusions regarding title to properties.

Very truly yours,

/s/    Jackson Kelly PLLC

JACKSON KELLY PLLC

EX-23.3

Exhibit 23.3

McGuireWoods LLP

One James Center

901 East Cary Street

Richmond, Virginia 23219

February 28, 2005

Virginia Electric and Power Company

701 East Cary Street

Richmond, Virginia 23219

Annual Report on Form 10-K

Ladies and Gentlemen:

We consent to the incorporation by reference into the statements made in regard to our firm in the Registration Statements of Virginia Electric and Power Company on Form S-3 (File Nos. 333-38510 and 333-96973) and related prospectuses of the legal conclusions that relate to the Company’s franchises and title to properties included in this Annual Report on Form 10-K.

Sincerely,

/s/ McGuireWoods LLP

EX-31.1

Exhibit 31.1

I, Jay L. Johnson, certify that:

1. I have reviewed this report on Form 10-K of Virginia Electric and Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d- 5(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2005
	/s/ Jay L. Johnson
	Jay L. Johnson
	President and Chief Executive Officer

EX-31.2

Exhibit 31.2

I, Paul D. Koonce, certify that:

1. I have reviewed this report on Form 10-K of Virginia Electric and Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d- 5(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2005
	/s/ Paul D. Koonce
	Paul D. Koonce
	Chief Executive Officer—Energy

EX-31.3

Exhibit 31.3

I, Mark F. McGettrick, certify that:

1. I have reviewed this report on Form 10-K of Virginia Electric and Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d- 5(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2005
	/s/ Mark F. McGettrick
	Mark F. McGettrick
	President and Chief Executive Officer—Generation

EX-31.4

Exhibit 31.4

I, G. Scott Hetzer, certify that:

1. I have reviewed this report on Form 10-K of Virginia Electric and Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d- 5(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2005
	/s/ G. Scott Hetzer
	G. Scott Hetzer
	Senior Vice President and Treasurer (Principal Financial Officer)

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, each of the undersigned officers of Virginia Electric and Power Company (the Company), certify that:

1. the Annual Report on Form 10-K for the year ended December 31, 2004 (the “Report”) of the Company to which this certification is an exhibit fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)).

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of December 31, 2004 and for the period then ended.

/s/ Jay L. Johnson

Jay L. Johnson

President and Chief Executive Officer

February 28, 2005

/s/ Paul D. Koonce

Paul D. Koonce

Chief Executive Officer—Energy

February 28, 2005

/s/ Mark F. McGettrick

Mark F. McGettrick

President and Chief Executive Officer—Generation

February 28, 2005

/s/ G. Scott Hetzer

G. Scott Hetzer

Senior Vice President and Treasurer

(Principal Financial Officer)

February 28, 2005