Back to GetFilings.com

Table of Contents

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2004

OR

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)

(804) 819-2000

(Registrant’s telephone number)

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

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

Table of Contents

Virginia Electric and Power Company

Table of Contents

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

Table of Contents

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

Table of Contents

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

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:

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

Table of Contents

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

Table of Contents

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

Table of Contents

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

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

2004 / Page 6

Table of Contents

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.

Table of Contents

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:

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

Item 6. Selected Financial Data

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

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

Table of Contents

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

Table of Contents

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

Table of Contents

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:

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:

2004 / Page 11

Table of Contents

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:

Results of Operations

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

Overview

2004 vs. 2003

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

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

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

Table of Contents

2003 vs. 2002

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

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

Analysis of Consolidated Operations

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

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:

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

2004 / Page 13

Table of Contents

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

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:

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:

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:

Operating Expenses and Other Items

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

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:

2004 / Page 14

Table of Contents

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:

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:

The growth factors in 2005 will be impacted by:

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.

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.

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

2004 vs. 2003

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

2004 / Page 15

Table of Contents

2003 vs. 2002

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

Energy

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

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

2004 vs. 2003

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

2003 vs. 2002

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

2004 / Page 16

Table of Contents

Delivery

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

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

2004 vs. 2003

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

2003 vs. 2002

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

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:

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:

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:

2004 / Page 17

Table of Contents

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:

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:

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

Table of Contents

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:

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.

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:

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

Table of Contents

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:

2004 / Page 20

Table of Contents

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 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.

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

Table of Contents

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:

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:

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

Table of Contents

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

Table of Contents

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.