ML051050483

ISFSI North Anna Power Station Units 1 and 2 and ISFSI Annual Reporting of Financial Information

ML051050483
Person / Time
Site:	Surry, North Anna, 07200002
Issue date:	04/01/2005
From:	Matthews W Virginia Electric & Power Co (VEPCO)
To:	Office of Nuclear Reactor Regulation
References
05-199
Download: ML051050483 (72)

Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 April 1, 2005 Director of Nuclear Reactor Regulation Serial No 05-1 99 U. S. Nuclear Regulatory Commission NLOS/vl[ I Washington, D. C. 20555-0001 Docket NQos. 50-280/281 50-338/339 72-2/16 License Nos. DPR-32/37 NPF-4f7 SNM-2501 /2507 VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

SURRY POWER STATION UNITS 1 AND 2 AND ISFSI NORTH ANNA POWER STATION UNITS 1 AND 2 AND ISFSI ANNUAL REPORTING OF FINANCIAL INFORMATION Pursuant to 10 CFR 140.21(e) regarding guarantees of payment of deferred premiums for power reactors, we are providing the following financial information:

1. Comparative Statements of Income for the three months ended December 31, 2004 and 2003.

2. Internal cash flow projection for calendar year 2005 with certification by an officer of the Company.

3. Statement ensuring availability of funds for payment of retrospective premiums without curtailment of required nuclear construction expenditures.

4. A copy of the Annual Report to Securities and Exchange Commission on Form 10-K for 2004.

In accordance with 10 CFR 140.7, a check for $1,000 was submitted to the NRC on November 1, 2004, as the associated minimum fee for the period November 15, 2004 through November 14, 2005.

This financial information is also being provided to address the annual reporting requirement for Independent Spent Fuel Storage Installations pursuant to 10 CFR 72.80(b). If there are any questions, please contact Mr. Dave Sommers at (804) 273-2823.

Very truly yours, W. R. Matthews Senior Vice President - Nuclear Operations Enclosures A

SN 05-199 Docket Nos. 50-280/281/338/339, 72-2/16

Subject:

Price-Anderson Submittal Page 2 of 2 cc: U. S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth St.,-SW,-Suite 23 T85 -

Atlanta, GA 30303-8931 U. S. Nuclear egufatory Commission Attention- Document Control Desk

-- - Wasfgington, -DC --20555-0001 Mr. S. R. Monarque NRC Project Manager U. S. Nuclear Regulatory Commission One White Flint North 11555 Rockville Pike M/S 8 H12 Rockville, MD 20852-2738 Mr. J. R. Strosnider, Director Office of Nuclear Material Safety and Safeguards U. S. Nuclear Regulatory Commission Two White Flint North 11545 Rockville Pike M/S 8 A23 Rockville, MD 20852-2738 Mr. N. P. Garrett NRC Senior Resident Inspector Surry Power Station Mr. J. T. Reece NRC Senior Resident Inspector North Anna Power Station

Virginia Electric & Power Co.

CONSOLIDATED STATEMENTS OF INCOME Quarter Ended December 31, 2004 2003 (millions)

Operating Revenue $ 1,433 $ 1,192 Operating Expenses Electric fuel & energy purchases, net 382 399 Piurchasd electrrtric nnnitv 129 144 Purchased gas 28 29 Other purchased energy commodities 185 61 Other operations & maintenance 558 435 Depreciation & amortization 127 114 Other taxes 38 39 Total operating expenses 1,447 1,221 Income from operations (14) (29)

Other income 17 24 Interest and Related Charges Interest expense - other 41 86 Interest expense - junior subordinated notes payable to affiliated trust 8 Distributions - mandatorily redeemable trust preferred securities 7 Total interest and related charges 49 93 Income before income taxes (47) (98)

Income taxes (38) (41)

Income before cumulative effect of a change (9) (57) in accounting principle Cumulative effect of a change in (105) accounting principle (net of income taxes of $64)

Net income (9) (162)

Preferred dividends 4 4 Balance available for common stock $ (13) S (166)

VIRGINIA ELECTRIC AND POWER COMPANY 2005 ESTIMATED INTERNAL CASH FLOW (Millions of Dollars)

January April July October; Estimated through through through through I 2005 March June September December Total Cash receipts $ 1,383 $ 1,324 $ 1,591 $ 1,320 $ 5,618 Less:

Cash for operations 960 852 931 816 3,559 Taxes 132 133 206 143 614 Interest 68 68 70 70 276 Dividends 120 123 219 137 599 Decommissioning trust 9 9 9 9 36 Changes in working capital/other (132) (4) (147) (79) (362)

Total cash flow (1) $ 227 $ 143 $ 304 $ 222 $ 896 (1) Before financing and construction requirements

VIRGINIA ELECTRIC AND POWER COMPANY

- - CERTIFICATE I, the undersigned, Thomas R. Bean, do hereby certify, pursuant to the guarantee requirements set forth in the Commission's letter dated June 15, 1977, that the cash flow projection for 2005, provided herewith, is based on the best available information known at this time and is a reasonably accurate projection of the company's 2005 cash flow.

Thomas R. Bean Vice President - Financial Management NOTARIAL SEAL Commonwealth of Virginia City of Richmond I, Brenda G. Long, certify that Thomas R. Bean is Vice President -

Financial Management for Dominion, and such certificate was signed on March 30, 2005.

Brenda G. Long 6 My commission expires: August 31, 2007

VIRGINIA ELECTRIC AND POWER COMPANY STATEMENT Based on the company's 2005 approved budget, the company estimates that 2005 construction and nuclear fuel expenditures (exclusive of Allowance for Funds Used During Construction) to be $8701 million. Maturity of securities in 2005 will total $122 million. It is expected that approximately $8963 million will be obtained from internal sources, which would exceed the expenditures above. The company is reasonably assured that, based on the best available cash flow projections which are provided herewith, curtailment of capital expenditures for required nuclear programs would not be required to cover the Price-Anderson maximum retrospective premium assessment for a single incident of $402.44 million ($100.6 million, including a 3 percent insurance premium tax for Virginia, for each of the four reactors owned by the Company with assessments not to exceed $105 million per reactor per year) currently in force.

from IOK page 22 - Plant and Equipment - 400m + 120m +350m = 870m 2 from IOK page 46 - Note 14 2005 Maturities = 12m 3 From Certified copy of 2005 estimated Internal Cash Flow- Virginia Electric and Power Co. - Certified for accuracy by Simon Hodges - VP Financial Planning 4 from I OK page 51 - Insurance (I00.6m x 4 = 402.4m) 5 from IOK page 51 -Insurance lOin

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 a 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 (LR.S. Employer of incorporation or organization) 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:

Name of Each Exchange Title of Each Class on Whkh 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 dais. Yes [3 No D 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 m of this Form 10-K or any amendment to this Form 10-K. iE3 Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).

Yes E No I1 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 htem Pge Number Numbr Part I

1. Business.................................................................................... 1

2. Properties.................................................................................... 6

3. Legal Proceedings ......................................................................... 7

4. Submission of Matters to aVote of Security Holders ................................................- 7 Part II

5. Market for the Registrant's Common Equity and Related Stockholder Matters ....... ............ 8.......

8

6. Selected Financial Data ..........................................................................

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

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 ...............  : .. ............ 5B 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 Propefties The Delivery segment electric distribution network includes approx-The Company imately 54,000 miles of distribution lines, exclusive of service level Virginia Electric and Power Company (the Company) is a regulated lines inVirginia and North Carolina. The right-of-way grants for public utility that generates, transmits and distributes power for most of the Company's electric lines have been obtained from the sale inVirginia and northeastern North Carolina. InVirginia, the apparent owner of real estate, but underlying titles have not been Company conducts business under the name 'Dominion Virginia examined except for transmission lines of 69kV or more .Where Power.' InNorth Carolina, the Company conducts business under rights-of-way have not been obtained, they could be acquired from the name 'Dominion North Carolina Power' and serves retail private owners by condemnation, if necessary. Many electric lines customers located inthe northeastern region of the state, are on publicly-owned property, where permission to operate can excluding certain municipalities. Inaddition, the Company sells be revoked.

electricity at wholesale to rural electric cooperatives, power marketers, municipalities and other utilities. Within this document, Sources of Fuel Supply the Company' refers to the entirety of Virginia Electric and Power Delivery's supply of electricity to serve its retail customers is Company, including its Virginia and North Carolina operations and primarily provided by the Generation segment. See Generation for all of its subsidiaries. additional information.

All of the Company's common stock isowned by its parent Seasonality company, Dominion Resources, Inc. (Dominion), a fully integrated*. Delivery's business typically'varies seasonally based on demand gas and electric holding company. for electricity by residential and commercial customers for cooling As of December 31, 2004, the Company had approximately and heating use due to changes intemperature.

7,100 full-time employees. Approximately 3,300 employees are subject to collective bargaining agreements.

The Company was incorporated in1909 as a Virginia public Energy service corporation. Its principal executive offices are located at Energy includes a regulated electric transmission system located in 701 East Cary Street, Richmond, Virginia 23219 and its telephone Virginia and northeastern North Carolina and the Company's Clear-number is (804) 819-2000. inghouse operations, which isresponsible for energy trading (exclusive of marketing excess utility generation), marketing and risk management activities.

Operating Segments During the fourth quarter of 2004, the Company performed an The Company manages its operations through three primary evaluation of its Clearinghouse trading and marketing operations, operating segments: Delivery, Energy and Generation. The Com- which resulted in adecision to exit certain energy trading activities pany also reports Corporate and Other functions as a segment. and instead focus on the optimization of company assets. Begin-While the Company manages its daily operations as described ning in2005, all revenue and expenses from the Clearinghouse's below, its assets remain wholly-owned by it and its legal sub- optimization of Company assets will be reported as part of the sidiaries. For additional financial information on business seg- results of the business segments operating the related assets.

ments and geographic areas, see Notes 1 and 23 to the As aresult of these changes, 2004 and 2003 results now reflect Consolidated Financial Statements. revenue and expenses associated with coal trading and marketing activities inthe Generation segment rather than the Energy segment.

Delivery Delivery includes the Company's electric distribution system and Competition customer service operations. Electric distribution operations serve Energy's electric transmission business isnot subject to competi-residential, commercial, industrial and governmental customers in tion for transmission service to loads served within its Virginia and Virginia and northeastern North Carolina. North Carolina service territories. Inconnection with transmission service to loads outside of its electric service territory, the Compa-Competition ny's electric transmission business competes with other electric Within Delivery's certificated service territory inVirginia and North transmission providers, primarily on the basis of rates and avail-Carolina, there is no competition for electric distribution service. ability of service.

Regulation r Regulation Delivery's electric retail service, including the rates it may charge Energy's electric transmission operations are subject to regulation to customers, issubject to regulation by the Virginia State Corpo- by the Federal Energy Regulatory Commission (FERC), the Virginia ration Commission (Virginia Commission) and the North Carolina Commission and the North Carolina Commission. See State Regu-Utilities Commission (North Carolina Commission). See Regulation lations and Federal Regulations in Regulation for additional

- State Regulations for additional information. information.

2004/Page 1

Properties adversely impact the Companys cost structure. Conversely, the The Energy segment has approximately 6,000 miles of electric Company may experience a positive economic impact to the extent transmission lines located in the states of North Carolina, Virginia it can reduce its fuel factor-related costs. Subject to market con-and West Virginia. Portions of the electric transmission lines cross ditions, any generation remaining after meeting utility system national parks and forests under permits entitling the federal needs is sold outside the Company's service area. See Regulation-government to use, at specified charges, surplus capacity inthe State Regulations and Regulation-Federal Regulations-line, if any exists. Environmental Regulations for additional information.

The Company maintains major interconnections with Progress' Properties Energy, American Electric Power Company, Inc., PJM-West and For a listing of the Company's generation facilities, see Item 2.

PJM. Through this major transmission network, the Company has Properties.

arrangements with these entities for coordinated planning, oper-ation, emergency assistance and exchanges of capacity and Sources ofFuel Supply energy. See Regional Transmission Organization (RTO) in Future Generation uses a variety of fuels to power its electric generation.

Issues and OtherMatters inItem 7.Management's Discussion and These include a mix of both nuclear fuel and fossil fuel as Analysis of Financial Condition and Results of Operations (MD&A). described further below.

Seasonality Nuclear Fuel - Generation utilizes primarily long-term contracts to.

The Energy segment isaffected by seasonal changes inthe prices support its nuclear fuel requirements. Worldwide market con-of commodities that it markets and trades. ditions 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 Generation planned fuel supply needs. Additional fuel is purchased as required Generation includes the Company's electric generation operations. to ensure optimum cost and inventory levels.

The Company's strategy for its electric generation operations focuses on serving customers inVirginia'and northeastern North Fossil Fuel - Generation utilizes coal, oil and natural gas in its Carolina. fossil fuel operations. Generation's coal supply is obtained through As a result of the reorganization of the Company's Clearing- long-term contracts and spot purchases. Oil-fired generation is house operations, Generation's 2004 and 2003 results now reflect used primarily to support heavier system generation loads during revenue and expenses associated with coal trading and marketing very cold or very hot weather periods. Additional utility require-activities performed by the Clearinghouse that were previously ments are purchased mainly under short-term spot agreements.

reported inthe Energy segment Firm natural gas transportation contracts (capacity) exist that InFebruary 2005, the Company paid $42 million incash and allow delivery of gas to Generation's facilities. Generation's assumed $62 million indebt inconnection with'the termination of. capacity pottfolio allows flexibil natural gas deliveries to its gas along-term power purchase agreement and acquisition of the turbine fleet, while minimizing ccsts.

related generating facility used by Panda-Rosemary, U'. anon- Seasonality utility generator, to provide electricity to the Cor6pany. See Sales of electricity for the Generation segment vary seasonally Restructuring of Contract with Non-Utility Generator in Future based on demand for electricity by residential and commercial Issues and Other Matters in MD&A for additional information. customers for cooling and heating use due to seasonal changes in Competition temperature.

For the Company's electric generation operations, retail choice has Nuclear Decommissioninq.

been available for all of the Company's Virginia electric customers Generation has four licensed, operating nuclear reactors at its since January 1,2003;. however, to date, competition inVirginia Surry and North Anna plants inVirgiria that serve customers of the' has not developed to the extent originally anticipated. See Company's regulated electric utility operations. Decommissioning Regulation-State Regulations. Currently, North Carolina does not represents the decontamination and removal of radioactive con-offer retail choice to electric customers. taminants from a nuclear power plant once operations have Regulation ceased, inaccordance with standards established by the Nuclear InVirginia and North Carolina, the Company's electric utility Regulatory Commission (NRC). Amounts collected from ratepayers generation facilities, along with power purchases, are used to and placed intrusts are being invested to fund the expected future serve its utility service area obligations. Due to 2004 deregulation costs of decommissioning the Surry and North Anna units.

legislation, revenues for serving Virginia jurisdictional retail load The total estimated cost to decommission the Company's four are based on capped rates through 2010 and the related fuel costs nuclear units is $1.5 billion based upon site-specific studies -

for the generating fleet, including power purchases, are subject to completed in2002. The Company expects to perform new cost afixed rate recovery through July 1,2007 when aone-time pro- studies in2006. The cost estimate assumes that the method of spective adjustment will be considered. During this transition completing decommissioning activities isprompt dismantlement period, the risk of fuel factor-related cost recovery shortfalls may During 2003, the NRC approved the Company's application for a 20-year life extension for the Surry and North Anna units. The 2004/Page2

Company expects to decommission the units during the period ments to the Virginia Restructuring Act and the Virginia fuel factor 2032 to 2045. statute. The amhndments extend capped base rates to December 31, 2010, unless modified or terminated earlier under the Virginia Surry North Anna Restructuring Act. Inaddition to extending capped rates, the Unit 1 Unit 2 Unit 1 Unit 2 Total amendments:

(millions)

• Lock in the Company's fuel factor provisions until the earlier of NRC license expiration year - 2032 2033 2038 2040 July 1,2007 or the termination of capped rates; Current cost estimate (2002 dollars) S 375 $ 368 S 391 $ 363 $1,497

• Provide for a one-time adjustment of the Company's fuel factor, Funds Intrusts at December 31, effective July 1,2007 through December 31, 2010 (unless.

2004 . - 313 308 256 242 1,119 capped rates are terminated earlier under the Virginia 2004contributionstotrusts 11 11 7 7 -36 Restructuring Act), with no adjustment for previously incurred over-recovery or under-recovery, thus eliminating deferred fuel accounting for the Virginia jurisdiction; and Corporate and Other

• End wires charges on the earlier of July 1,2007 or the The Company also has a Corporate and Other segment. Corporate termination of capped rates, consistent with the Virginia and Other represents the Company's corporate and other functions Restructuring Act's original timetable.

and specific items attributable to the Company's operating seg- The risk of fuel factor-related cost recovery shortfalls may ments that are reported inCorporate and Other. adversely impact the Company's cost structure during the tran-sition period and it could realize the negative economic impact of any such adverse event. Conversely, the Company may experience Regulation a positive economic impact to the extent that it can reduce its The Company is subject td regulation by the Securities and fuel factor-related costs for its electric utility generation-related Exchange Commission (SEC), FERC, the Environmental Protection operations.

Agency (EPA). Department of Energy (DOE), the NRC, the Army . .-. Other amendments to the Virginia Restructuring'Act were also Corps of Engineers, and other federal, state and local authorities. 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 State Regulations default service needs. Under the minimum stay exemption pro-The Company is subject to regulation by the Virginia Commission gram, large customers with a load of 500 kW or greater would be and the North Carolina Commission. exempt from the twelve-month minimum stay obligation under The Company holds certificates of public convenience and capped rates if they return to supply service from the incumbent necessity authorizing it to maintain and operate its electric facili- utility at market-based pricing after they have switched to supply ties now inoperation and to sell electricity to customers. However, service with a competitive service provider.

it may not construct or incur financial commitments for con- The wires charge exemption program would allow large struction of any substantial generating facilities or large capacity industrial and commercial customers, as well as aggregated transmission lines without the prior approval of various state and customers in all rate classes, to avoid paying wires charges when federal government agencies. selecting supply service from a competitive service provider by agreeing to market-based pricing upon return to the incumbent Status of ElectricDeregulation in Virginia electric utility. Customers electing this option would waive the The Virginia Electric Utility Restructuring Act (Virginia right to return to capped rate service from the incumbent electric Restructuring Act) was enacted in1999 and established a plan to utility. The program is limited to the first 1,000 Mw of load or eight restructure the electric utility industfy'ii Virginia. The Virginia percent of the utility's prior year Virginia adjusted peak load inthe Restructuring Act addressed, among other-things: capped base first 18 months of the program.

rates, RTO participatioh, retail choice, the recovery of stranded InJanuary 2005, the Company filed compliance plans and the costs and the functional separation-of a utility's electric generation required market-based pricing methodology for both programs with from its electric transmission and distribution operations. the Virginia Commission. To encourage a successful program and Retail choice has been available to all of the Company's the development of retail competition, the Company has proposed Virginia regulated electric customers since January 1,2003. The that customers that enroll with a competitive service provider in Company has also separated its generation, distribution and the wires charge exemption program in 2005 be allowed to return transmission functions through the creation of divisions.'Codes of to service with the Company at capped rates after October 2007 conduct ensure that Virginia Power's generation and other divi- instead of market-based pricing. The Virginia Commission must sions operate independently and prevent cross-subsidies between approve these proposals prior to implementation.

the generation and other divisions. In December 2004, the Company filed its annual market prices/

Since the passage of the Virginia Restructuring Act, the com- wires charges compliance plan with the Virginia Commission.

petitive environment has not developed inVirginia as anticipated. Calculation of the 2005 wires charges in accordance with the InApril 2004, the Governor of Virginia signed into law amend- 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 Federal Regulations . '

wires charges during 2005. The Company's decision to forego wires charges in2005 is not intended to set a precedent for Public Utility Holding CompanyAct of 1935(1935Act) subsequent periods. The Company intends to collect wires charges Dominion is a registered holding company under the 1935 Act. The in future periods should the Virginia Commission-approved*' 1935 Act and related regulations issued by the SEC govern activ-methodology determine that wires charges are applicable. ities of Dominion and its subsidiaries, including the Company, with See Status of Deregulation in Virginia inFuture Issues and respect to the issuance and acquisition of securities, acquisition Other Matters inMD&A for additional information on capped base and sale of utility assets, certain transactions among affiliates, rates, stranded costs and RTO participation.- engaging in business activities not directly related to the utility or energy business and other matters. The Company's activites in RetailAccessPilot Programs. thesa areas may also be regulated at the state level by the Virginia The three retail access pilot programs, approved by the ViWginia Commission and the North Carolina Commission. Insome cases, Commission in 2003, continue to be'available to customers.-These the SEC's rules under the 1935 Act provide that the obtaining of' programs are to run'through the remainder of the capped rate state approvals will also suffice for 1935 Act purposes, subject to period and will make available to qonipeiitive service providers up. the fulfillment of certain post-transaction reporting requirements.

to 500 megawatts of road,'ith pote9a4'pparti0iation of. more.

than 65,000 customiers frdmavaietyi of customer classes.;

Rate Matters * '  ;>. . . . - Federal Energy Regulatory Commission Virginia-ln December 2003, the Virginia Commission approved Under the Federal Power Act, FERC regulates wholesale sales'of the Companys proposed settlement of its 2004 fuel factor increase electricity and transmission of electricity in interstate commerce by of $386 million. The settlement includes a recovery period for the public utilities. The Company sells electricity inthe wholesale' under-recovery balance over threeand a ye market under its market-based sales tariff authorized by FERC butt

$171 million of the $386 million was recovered in2004 with $85 does not make wholesale power sales under this tariff to loads-million to be recovered in2005, $87 million in 2006 and $43 million located within its service territory. Inaddition, the Company hasi in the first six months of 2007. FERC approval of a tariff to sell wholesale power at capped rates As a result of amendments to the Virginia Resiructuring Act in based on its embedded cost of generation: This cost-based sales 2004, the Company's capped based rates were extended to tariff could be used to sell to loads Within'or outside its service December 31, 2010. Inaddition, the CormIpany's fuel factor provi- territory. Any such sales would be voluntary. The Companys sales sions were frozen until July 1,2007,'after which they can be only of natural gas, liquid hydrocarbon by-products and oil inwholesale' adjusted once more through December 31, 2010. See Status of markets are not regulated by FERC.

Electric Deredulation in Vrginia above for additional informatiorn .The'irginia Restructuring Act requires that the Company join'- '

regarding the Virginia Restructuring Act amendments., an RTO, and FERC encourages RTO formation as a means to foster North Carolina-In connection with the North Carolina wholesale market formation. The Company and PJM Inter- ' -

Commission's approval of Dominion's acquisition of Consolidated connection, LLC (PJM) entered into an agreement in September '

Natural Gas Company (CNG), the Company agreed not to request 2002 that provides for, subject to regulatory approval and certain,'

an increase in North Carolina retail electric base rates before provisions, the Company to become a member of PJM arid tiansfer 2006, except for certain events that would have a significant functional control of its electric transmission facilities to PJM for financial impact on the Company's electric'utility operations. Fuel inclusion in a new PJM South Region. In October 2004, FERC' rates are still subject to change under the annual fuel cost adjust- issued an order conditionally approving the Company's application ment proceedings. However inApril 2004, the North Carolina to join P.IM, and inNove~mber 2004; the Virginia Commission Commission commenced an investigation into the Company's approved the Companys application to joiin PJM 'subject to certain North Carolina base rates'and subsequently ordered the Company terms and conditi6ns. The North Carolina Commissi'on 6videntiary to file a general rate case to show cause why its North Carolina hearing was held inJanuary 2005. The Company cainnot predict base rates should not be reduced. The rate case was filed in the outcome of this matter at this tiaie. '

September 2004 and in February 2005, the Company reached a In a separate order issued inSeptember 2004, FERC granted tentative settlement with parties inthe case that issubject to authority to the Company and its affiliates with market based rate North Carolina Commission approval before becomin g effective. authority to charge niarket based rates for s'alds of electric energy.

and capacity to loads located within the Companrys service tern-tory upon its integration into PJM. For'additional information', see RTOin Future lssues and OtherMatters 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 scop ,fof the th affiliates affiliate 2004 /Page 4

covered by the standards and is designed to prevent transmission Company cannot predict the financial impact, if any, on its oper-providers from giving their marketing functions or affiliates undue ations at this tinie.

preferences. The United States Congress is considering various legislative InJune 2004, FERC approved the Company's filing to provide proposals that would require generating facilities to comply with optional backup supply service to competitive service providers more stringent air emissions standards. Emission reduction serving retail customers, including the retail pilot programs, in the requirements under consideration would be phased in under a Companys service territory inVirginia. The filing addressed variety of periods of up to 15 years. If these new proposals are competitive service providers' concerns with the availability of adopted, additional significant expenditures may be required.

transmission capacity to move energy into Virginia. The backup InJuly 2004, the EPA published new regulations that govern supply service will allow competitive service providers to continue existing utilities that employ a cooling water intake structure, and to serve their customers inthe Company's service area inVirginia whose flow levels exceed a minimum threshold. The EPA's rule during periods of supply interruption. This isan interim solution presents several compliance options. The Company is evaluating until the Company is integrated into PJM. 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 Environmental Regulations predict the outcome of the EPA regulatory process or state with Each operating segment faces substantial regulation and corn- any certainty what specific controls may be required.

pliance costs with respect to environment3l matters. For dis- The Company has applied for or obtained the necessary environ-cussion of significant aspects of these matters, includ.ng current mental permits for the operation of its regulated facilities. Many of and planned capital expenditures relating to environmental com- these permits are subject to re-issuance and continuing review.

pliance, see Environmental Matters inFuture Issues and Other Nuclear Regulatory Commission Matters in MD&A. Additional information can also be found ir. All aspects of the operation and maintenance of the Company's Item 3. Legal Proceedings and Note 19 to the Consolidated Finan- nuclear power stations, which are part of the Generation segment, cial Statements. are regulated by the NRC. Operating licenses issued bythe NRC From time to time, the Company may be identified as a poten-are subject to revocation, suspension or modification, and the tially responsible party to a Superfund site. The EPA (or a state) operation of a nuclear unit may be suspended if the NRC can either (a)allow such a party to conduct and pay for a remedial determines that the public interest health or safety so requires.

investigation, feasibility study and remedial action or (b)conduct From time to time, the NRC adopts new requirements for the the remedial investigation and action and then seek reimburse- operation and maintenance of nuclear facilities. Inmany cases, ment from the parties. Each party can be held jointly, severally and these new regulations require changes inthe design, operation strictly liable for all costs. These parties can also bring contribution and maintenance of existing nuclear facilities. If the NRC adopts actions against each other and seek reimbursement from their such requirements inthe future, it could result in substantial insurance companies. As a result, the Company may be respon- increases in the cost of operating and maintaining the Company's sible for the costs of remedial investigation and actions under the nuclear generating units.

Superfund Act or other laws or regulations regarding the The NRC also requires the Company to decontaminate nuclear rerrediation of waste. The Company dces not believe that any facilities once operations cease. This process is referred to as currently identified sites will result insignificant liabilities.

decommissioning, and the Company is required by the NRC to be InJanuary 2004, the EPA proposed additional regulations financially prepared. For information on the Companys decom-addressing pollution transport from electric generating plants as missioning trusts, see Generatior-NuclearDecomrnissioning and well as the regulation of mercury and r.;ckel emissions. These Note 8 to the Consolidated Financial Statements.

regulatory actions, inaddition to revised regulations to address regional haze, are expected to be finalized in2005 and could require additional reductions inemissions from the Company's fossil fuel-fired generating faci!ities. If these new emission reduc-tion requirements are imposed, additional significant expenditures may be required.

InMarch 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 (N0) and sulfur dioxide (SO 2) reductions from electrical generating units inthirteen states, claiming emis-sions from the electrical generating units inthose states arecon-tributing to air quality problems inNorth Carolina. The Company has electrical generating units intwo 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 2004/Page 5

Item 2.Properties The Generation segment provides electricity for use on a wholesale and a retail level. The Generation segment can supply The Company owns its principal properties infee (except as electricity demand either from its generation facilities inVirginia, indicated below), subject to defects and encumbrances that do not North Carolina and West Virginia or through purchased power interfere materially with their use. Substantially all of the Company's contracts when needed. The following table lists the Company's property is subject to the lien of the mortgage securing its First and generating units and capability.

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.

Virginia Electric and Power Company's Power Generation Net Summer Plant Location Primary Fuel Type Capability (Mw)

North Anna Mineral, VA Nuclear 1,628(a)

Surry Surry,VA Nuclear 1,598 ML 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) DumfrlesVA 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()

Total Capacity 18,437 Note: (CT) denotes combustion turbine and (CC) denotes combined cyde (a) Exducles 11.6 percent undivided interest owned by Old Dominion Electric Cooperative lODECI.

b) Excludes 50 percent urdivided interest owned by ODEC.

(c) Generating unit operated by the Company under aleasing arrangement (d) Excludes 40 percent undivided interest owned by Alle*ny Generating Conparry. asubsidiary of Aflegherry Energy, Inc.

le) Totals may not add due to rounding.

(I Purhdase capacity includes generation from the Batesville facility. The Company has decided to divest its interest inthe long-term power olling contract associated with tNs facility. See Lorg-Tarm Power Tollirn Contractin MD&A for additional infornation.

2004/Page 6

Item 3. Legal Proceedings Item 4. Submission of Matters to a Vote of From time to time, the Company is alleged to be inviolation or in Security Holders default under orders, statutes, rules or regulations relating to the None.

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. Admin-istrative proceedings may also be pending on these matters. In addition, inthe ordinary course of business, the Company is involved invarious 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 inItem 1.Business, Future Issuesand 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 isa party.

- 'L'.t .

4 20041 Page 7

Part 11 Item 5.Market for the Registrant's The Company paid quarterly cash dividends on its common Common Equity and Related Stockholder stock as follows:

Matters Quarter Dominion Resources, Inc. (Dominion) owns all of the Company's 1st 2nd 3rd 4th common stock. (millions) 2004 $126 $101 $194 $ 97 2003 125 113 213 109 Restrictions on the payment of dividends by the Company are -

discussed inNote 17 to the Consolidated Financial Statements.

Item 6.Selected Financial Data 200411) 20312) 2002 200Xlt 200(1')

(millions)

Operating revenue $ 5,741 S 5.437 S 4,972 $ 4,944 $ 4,791 Income before cumulative effect of changes inaccounting principles 431 582 773 446 558 Cumulative effect of changes in3ccounting principles (net of income taxes of $14 in2003 and$11 in2000) - (21) - - 21 Net income 431 561 773 446 579 Balance available for common stock 415 546 757 423 543 Total assets 17,318 15,834 15,588 14,597 14,282 Long-term debts 4,958 4,744 3,794 3,704 3,561 Preferredsecuritiesofsubsidiarytrustl5) - - 400 135 135 (1l 2004 results include: a$112 million after-tax charge reflecting the Companysvaluation of its interest inalong-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: sin2 million of after-tax incremental restoration expenses associated with Hurricane Isabel; a$55 million after-tax charge resulting from the termi-nation of long-term power purchase agreements and a$21 milflon net after-tax loss for the adoption of accounting standards that resulted inthe recogr.ition of the cumu-lative effect of changes inaccounting principles, see Note 3to the Consolidated Financial Statements.

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

14)200 results include acumulative effect of a change inaccounting principle, resulting from achange inthe method of calculating the market-related value of pension iian assets.

(5)Upon adoption of Financial Accounting Standards Board Interpretation No. 46 (revised December 2003L Consolidation of Vanable lnteast Entities on December31, 2003 with respect to aspecial 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 3to th Consolidated Financial Statements.

Item 7.Management's Discussion and 0 Selected Information-Energy Trading Activities Analysis of Financial Condition and Sources and Uses of Cash Future Issues and Other Matters Results of Operations 0 Risk Factors and Cautionary Statements That May Affect Future Management's Discussion and Analysis of Financial Condition and Results 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 inconjunction with the Con- Forward-Looking Statements solidated Financial Statements. The 'Company' is used throughout This report contains statements concerning the Company's expect-MD&A and, depending on the context of its use, may represent ations, plans, objectives, future financial performance and other any of the following: the legal entity, Virginia Electric and Power statements that are not hIstorical'facts. These statements are Company, one of Virginia Electric and Power Companys con- 'forward-looking statements' within the meaning of the Private solidated subsidiaries or the entirety of Virginia Electric and Power Securities Litigation Reform Act of 1995. inmost cases, the reader Company and its consolidated subsidiaries. The Company is a can identify these forward-lcoking statements by words such as wholly-owned subsidiary of Dominion Resources, Inc. (Dominion). aanticipate.' 'estimate,' forecast,' 'expect,' believe,' 'should,'

'could,' 'plan,' may" or other similar words.

The Company makes forward-looking statements with full Contents of MD&A knowledge that risks and uncertainties exist that may cause actual The MD&A consists of the following information: results to be materially different from predicted results. Factors

• Forward-Looking Statements that may cause actual results to differ are often presented with the

• Introduction forward-looking statements themselves. Additionally, other risks

• Accounting Matters that may cause actual results to differ from predicted results are

• Results of Operations set forth inRisk factors and Cautionaiy Statements That May

• Segment Results of Operations Affect hFture Results.

20041 Page 3

The Company bases its forward-looking statements on manage- ...Variability inexpenses for the Generation segment relates ment's beliefs and assumptions using informition av'ailable at the primarily to the cost fuelIfconsumed, labor and benefits, and the time the statements are made. The Company cautions the reader timing, duration and costs of scheduled and unscheduled outages.

not to place undue reliance on its forward-looking statements As a result of the reorganization of the Company's Clearing-because the assumptions, beliefs, expectations and projections house operations (Clearinghouse), Generation's 2004 and 2003 about future events may, and often do, materially differ from results now reflect revenue and expenses associated with coal actual results. The Company undertakes no obligation to update trading and marketing activities performed by the Clearinghouse any forward-looking statement to reflect developments occurring that were previously reported inthe Energy segment.

after the statement is made. Energy includes aregulated electric transmission system located inVirginia and northeastern North Carolina, and the oper-ations of the Clearinghouse, which are responsible for energy Introduction trading (exclusive of marketing excess utility generation),

Virginia Electric and Power Company (the Company), a Virginia marketing and risk management activities.

public service company, is a wholly-owned subsidiary of Dominion. The Energy segment's revenue and cash flows are derived from The Company is a regulated public utility that generates, transmits both regulated and nonregulated operations..

and distributes electricity within an area of approximately 30,000 Revenue and cash flows provided by regulated electric trans-square-miles inVirginia and northeastern North Carolina. It serves mission operations are based primarily on rates established by tha approximately 2.3 million retail customer accounts, including Federal Energy Regulatory Commission (FERC). Variability inrevenue governmental agencies, and wholesale customers such as rural and cash flows provided by this business results from fluctuation in electric cooperatives, municipalities, power marketers and other rates and the demand for services, which isprimarily weather dependent. Variability inexpenses relates largely to operating and utilities. The Virginia service area comprises about 65% of Virgin%.

maintenance expenditures, including decisions regarding use of ia's total land area, but accounts for over 80% of its population.

resources for operations and maintenance or capital-related The Company has trading relationships beyond the geographic' activities.

limits of its retail service territory where it buys and sells natural, Revenue and cash flows for the Energysegment's Clearing-gas, electricity and other energy-related commodities.

house business are subject to variability associated with changes The Company's businesses are managed through three incommodity prices associated with both physical and financial operating segments: Generation. Energy and Delivery. The con- commodity contracts. Certain hedging and trading activities may tributions to net income by the Company's operating segments are require cash deposits to satisfy margin requirements. Inaddition, determined based on a measure of profit that executive manage- reported earnings for this segment reflect changes inthe fair value ment believes represents the segments' core earnings. As a result, of certain derivatives; these values may change significantly from certain specific items attributable to those segments are not period to period. Variability inexpenses for these nonregulated included in profit measures evaluated by executive management in businesses relates largely to labor and benefits and the costs of assessing segment performance or allocating resources among the purchased commodities for resale and payments under financially-segments. Those specific items are reported inthe Corporate and settled contracts.

Other segment. During the fourth quarter of 2004, the Company performed an Generation includes the Companys electric generation oper- evaluation of its Clearinghouse trading and marketing operations, ations. The generation mix is diversified and includes coal, nuclear, which resulted inadecision to exit certain energy trading activities gas, oil, hydro and purchased power. The Companys strategy for and instead focus on the optimization of company asseti. Begin-its electric generation operations focuses on serving customers in ning in2005, all revenue and expenses from the Clearinghouse's Virginia and northeastern North Carolina. Its generation facilities optimization of company assets will be reported as part of the are located in Virginia, West Virginia and North Carolina. results of the business segments operating the related assets, in Utility generation operations represent the Generation seg- order to better reflect the performance of the underlying assets. As ment's source of revenue and cash ftos. These operations are a result of these changes, 2004 and 2003 results now reflect sensitive to external factors, primarily weather and fuel prices. . - revenue and expenses associated with coal trading and marketing Currently, revenue from utility operations largely reflects the activities inthe Generation segment.'

capped rates charged to customers inVirginia. the majority of its Delivery includes the Company's electric distribution system utility customer base. Under Virginia's current deregulation legis- and customer service operations. The electric distribution system lation, electric base rates are capped through 2010. Under capped serves residential, commercial, industrial and governmental rates, changes in the Generation'segment's operating costs, - customers inVirginia and northeastern North Carolina.

particularly with respect to fuel, relative to costs used to establish Revenue and cash flows provided by electric distribution oper-the capped rates, will impact the Company's earnings.. ations are based primarily on rates established by state regulatory The Company markets its generation resources not needed to authorities and state law. Variability inthe Delivery segment's serve utility customers as part of its management of utility system revenue and cash flows relates largely to changes insales volumes, resources in the Generation segment. which are' primarily weather' sensitive.

The Generation segment has reduced costs by terminating Variability inexpenses results from changes inthe cost of certain long-term power purchase agreements. routine maintenance and repairs (including labor and benefits as 2004 /Page 9

well as decisions regarding the use of resources for operations and losses on cash flow hedges from accumulated other compre-mair.tenance or capital-related activities). hensive income (loss) (A0C) into earnings.

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. Use of estimates in long-livedassetimpairmenttesting Impairment testing for an individual or group of long-lived assets or intangible assets with definite lives is required when circum-stances indicate those assets may be impaired. When an asset's Accounting Matters carrying amount exceeds the undiscounted estimated future cash Critical Accounting Policies and Estimates flows associated with the asset, the asset is considered impaired The Company has identified the following accounting policies, to the extent that the asset's fair value is less than its carrying including certain inherent estimates, that as a result of the judg-amount. Performing an impairment test on long-lived assets ments, uncertainties, uniqueness and complexities of the under-lying accounting standards and operations involved, could result in involves management's judgment inareas such as identifying circumstances indicating an impairment may exist, identifying and material changes to its financial condition or results of operations grouping affected assets and developing the undiscounted and under different conditions or using different assumptions.

discounted estimated future cash flows (used to estimate fair value Management has discussed the development, selection and dis-inthe absenice of market-based value) associated with the asset, closure of each of these policies with the Company's Audit including the selection of an appropriate discount rate. Although Committee.

cash flow estimates used by the Company would be based on relevant information available at the time the estimates are made, Accounting for derivative contracts at fair value estimates of future cash flows are, by nature, highly uncertain and.

The Company uses derivative contracts (primarily forward pur- may vary significantly from actual results. For example, estimates chases and sales, swaps, options and futures) to buy and sell of future cash flows would contemplate factors such as the energy-related commodities and to manage its commodity and expected use of the asset, including future production and sales financial market risks. Derivative contracts; with certain levels, and expected fluctuations of prices of commodities sold and exceptions, are subject to fair value accounting and are reported consumed. During 2004, the Company did not test any significant on the Consolidated Balance Sheets at fair value. Accounting long-lived assets or asset groups for impairmeht as no circum-requirements for derivatives and related hedging activities are stances arose that indicated aniimpairment may exist, complex and may be subject to further clarification by standard-setting bodies. Asset retirement obligations Fair value of derivatives is based on actively quoted market The Company recognizes liabilities for the expected cost of retiring prices, if available. In the absence of actively quoted market tangible long-lived assets for which a !egal obligation exists.

prices, the Company seeks indicative price information from These asset retirement obligations (AROs) are recognized at fair external sources, including broker quotes and industry pub- value as incurred, and are capitalized as part of the cost of the lications. If pricing information from external sources is not avail- related tangible long-lived assets. Inthe absence of quoted market able, the Company must estimate prices based an available prices, the Company estimates the fair value of its AROs using historical and near-term future price information and use of stat- present value techniques, in which the Company makes various istical methods. For options and contracts with option-like charac- assumptions including estmates of the amounts and timing of .

teristics where pricing information is not available from external future cash flows associated with retirement activities, credit-sources, the Company generally uses a modified Black-Scholes adjusted risk free rates and cost escalation rates. AROs currently Model that considers time value, the volatility of the underlying reported on the;Company's Consolidated Balance Sheets were commodities and other relevant assumptions. The Company uses measured during a period of,historically low interest rates. The other option models when contracts involve different commodities impact on measurements of new AROs, using different rates inthe or commodity locations and when contracts allow either the buyer future, may be significant. The Company did not recognize any or seller the ability to exercise within a range of quantities. For new, significantiAROs in 2004. Inthe future, if the Co'npany contracts with unique characteristics, the Company estimates fair revises anyassumptions used to calculate the fair value of existing value using a discounted cash flow approach. If pricing information AROs, the Company will adjust the carrying amount of both the is not available from external sources, judgment is required to ARO liability and related long-lived asset. The Company records develop estimates of fair value. For individual contracts, the use of accretion expense, increasing the ARO liability, with the passage different valuation models or assumptions could have a material of time. In2004 and 2003, the Company recognized $42 million and effect on the contract's estimated fair value. $38 million, respectively, of accretion expense, and expects to For cash flow hedges of forecasted transactions, the Company incur $45 million in2005.

must estimate the future cash flows represented by the forecasted A significant portion of the Company's AROs relate to the transactions, as well as evaluate the probability of occurrence and future decommissioning of its nuclear facilities. At December 31, timing of such transactions. Changes in conditions or the occur- 2004, nuclear decommissioning AROs, which are reported inthe rence of unforeseen events could require discontinuance of hedge Generation segment, totaled $755 million, representing approx-accounting or could affect the timing for reclassification of gains or imately 97% of the Company's total AR Os. Based on their sig-nificance, the following discussion of critical assumptions inherent 2004/Page 10

indetermining the fair value of AROs relates to those associated ability of tax planning strategies that can be implemented, if with the Company's nuclear decommissioning obligations. necessary, to realize deferred tax assets. Failure to achieve fore-The Company obtains from third-party experts periodic site- casted taxable income or successfully implement tax planning' specific 'base year' cost studies inorder to estimate the nature, strategies might affect the ultimate realization of deferred tax cost and timing of planned decommissioning activities for its assets.

nuclear plants. These cost studies are based on relevant Newly Adopted Accounting Standards information available at the time they are performed; however, estimates of future cash flows for extended periods are by nature During 2004 and 2003, the Company was required to adopt several new accounting standards, the requirements of which are dis-highly uncertain and may vary significantly from actual results. In cussed inNotes 2 and 3 to the Consolidated Financial Statements.

addition, these cost estimates are dependent on subjective factors, including the selection of cost escalation rates, which the Com- The accounting standards adopted during 2003 affect the com-pany considers to be a critical assumption. parability of the Company's Consolidated Statements of Income.

The Company determines cost escalation rates, which repre- The following discussion is presented to provide an understanding sent projected cost increases over time, due to both general of the impacts of those standards on that comparability.

inflation and increases in the cost of specific decommissioning RN46R activities, for each of its nuclear facilities. The weighted average The adoption of Financial Accounting Standards Board (FASB) cost escalation used by the Company was 3.28%. The use of alter- Interpretation No.46 (revised December 2003), Consolidation of native rates would have been material to the liabilities'recognized.' Variable Interest Entities, (FIN 46R) on December 31, 2003 with For example, had the Company increased the cost escalation rate respect to special purpose entities, affected the comparability of by 0.5% to 3.78%, the amount recognized as of Decermber 31, the Company's 2004 Consolidated Statement of Income to prior 2004 for its AROs related to nuclear decommissioning would have years as follows:

been $148 million higher.

• The Company was required to consolidate a variable interest Accounting for regulated operations lessor entity through which the Company had financed and The Company's accounting for its regulated electric operations leased a new power generation project. As a result the differs from the accounting for nonregulated operations inthat the Consolidated Balance Sheet as of December 31, 2003 reflects Company is'required to reflect the effect of rate regulation inits an additional $364 million in net property, plant and equipment Consolidated Financial Statements. Specifically, the Company's and deferred charges and $370 million of related debt. In2004, regulated operations record assets and liabilities that the Company's Consolidated Statement of Income reflects nonregulated companies would not report under accounting princi-' depreciation expense on the net property, plant and equipment pies generally accepted in the United States of America. When ii and interest expense on the debt associated with this variable is probable that regulators will allow for the recovery of current interest lessor entity, whereas inprior years, it reflected as rent costs through future' rates charged to cusitomers, the Company' expense in other operations and maintenance expense, the defers these costs that otherwise would be expensed by non-, lease payments to this entity; and regula-ed companies and recognizes regulatory assets inits finan-

• Inaddition, under FIN 46R, the Company reports as long-term cial statements. Likewise, the Company recognizes regulatory debt its junior subordinated notes held by a capital trust rather liabilities inits financial statements when it is probable that regu- than the trust preferred securities issued by the trust. As a latGrs will a'iow for customer credits through future rates and result, in 2004, the Company reported interest expense on the when revenue is collectad from customers for expenditures that junior subordinated notes rather than preferred distribution are not yet incured. expense on the trust preferred securities.

Management evaluates whether or not recovery of its regu- SFAS No. 143 latory assets through futu, e regulated rates Isprobable and makes Adopting Statement of Financial Accounting Standards (SFAS) No.

various assumptions inits analyses. The expectations of future 143, Accounting fkrAsset Retirement Obligations, on January 1, recovery are generally based on orders'issued-by regulatory 2003 affected the comparability of the Company's 2004 and 2003 commissions or historical experience, as weli'as discussions with Consolidated Statements of Income to the prior year as follows:

applicable regulatory authorities. If recovery of regulatory assets is

• Accretion of the AROs for nuclear decommissioning is reported determined to be less than probable,'the regulatory asset will be inother operations and maintenance expense. Previously, written off and an expense will be recorded inthe period such expenses associated with the provision for nuclear' assessment is made. Management currently believes the recovery decommissioning were reported in depreciation expense and in of its regulatory assets is probable. See Notes 2 and 11 to the other income (loss); and Consolidated Financial Statements.

• Realized and unrealized earnings of trusts available for funding Income Taxes decommissioning activities at the Company's nuclear plants are Judgment is required indeveloping the Company's provision for recorded inother income (loss) and A00, as appropriate.

income taxes, including the determination of deferred tax assets Previously, as permitted by regulatory authorities, these and any related valuation allowance. The Company evaluates the earnings, along with an offsetting charge to expense for the probability of realizing its deferred tax assets on a quarterly basis accretion of the decommissioning liability, were both reported by reviewing its forecast of future taxable income and the avail- inother income (loss).

2004/Page 11

E17F02-3 and 3-11

• The elimination of fuel deferral accounting for the Virginia The adoption of Emerging Issues Task Force (EITF) Issue No. 02-3, jurisdiction, which resulted in the recognition of fuel Issues IMvolved in Accounting for Derivative Contracts Held for expenses in excess of amounts recovered in fixed fuel rates.

Trading Purposes and Contracts Involved in Energy Trading and

• A net loss from energy trading and marketing activities, Risk ManagementActivities, and related EITF Issue No. 03-11, resulting primarily from the effects of:

Reporting Realized Gains and Losses on Dervative Instriments

• Unfavorable price changes on electric trading margins; That Are Subject to FAS6 Statement No. 133 and Not 'Heldfor

• The transfer of certain wholesale electric contracts to a Trading Purposes as Defined in Issue No. 02-3, changed the Dominion subsidiary in 2003; timing of recognition inearnings for certain Clearinghouse energy-

• Comparatively lower price volatility on natural gas option related contracts, as well as the financial statement presentation positions; and of gains and losses associated with energy-related contracts. The

• Net losses associated with the settlement of a portfolio of Consolidated Statement of Income for 2002 was not restated. Prior finarci3l derivatives held as economic hedges for a portion to 2003, all energy trading contracts, including non-derivative of Dominion's 2054 natural gas production.

contracts, were recorded at fair value with changes infair value and settlements reported in revenue on a net basis. Specifically, The decrease in net income was also impacted by the following adopting EITF 02-3 and 03-11 affected the comparability of the specific items recognized in2004 and reported inthe Corporate Company's 2004 and 2003 Consolidated Statements of Income to and Other segment

• A $112 million after-tax charge, reflecting the Company's the prior year as follows:

valuation of its interest ina long-term power tolling contract,

• For derivative contracts not held for trading purposes that involve physical delivery of commodities, unrealized gains and which issubject to a planned divestiture inthe first quarter of 2005, as a result of its exit from certain energy trading losses and settlements on sales contracts are presented in activities. The charge is based on the Company's evaluation of revenue, while unrealized gains and losses and settlements on preliminary bids received from third parties, reflecting the purchase contracts are reported in expense; and expected amount of consideration that would be required by a

• Non-derivative energy-related contracts, previously subject to third party for its assumption of the Company's interest inthe fair value accounting under prior accounting guidance, are contract recognized as revenue or expense on a gross basis at the time

• $43 million net after-tax charges resulting from the termination of contract performance, settlement or termination.

of certain long-term power purchase agreements, and

• A $7million after-tax charge related to an agreement to settle a class action lawsuit involving a dispute over the Company's Results of Operations rights to lease fiber-optic cable along a portion of its electric Presented below isa summary of contributions by the Company's transmission corridor; partially offset by operating segments to net income:

• An $11 million after-tax benefit to adjust expenses accrued in Year Ended December 31, 2003 associated with restoration activities related to Hur.icana 2004 2003 2002 Isabel.

(millions) Inaddition, the decrease innet income was impacted by the Generation $ 407 $406 $486 specific items recognized in2003 and reported inthe Corporate Energy (10) 100 28 and Other segment, as described below.

Delivery 288 282 255 Operating segments 586 788 769 Corporate and Other (15) (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 incoal trading and marketing activities,

• A reduction incapacity 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 2004/ Psge 12

2003vs.2002 The decrease innet income was also impacted by the following Net income decreased 27% to $561 million, as compared to 2002, specific items recognized in 2003 and reported in the Corporate primarily reflecting: and Other segment:

• A lower contribution from utility generation operations, * $122 million after-tax incremental restoration expenses primarily due to comparably milder weather, recognition of associated with Hurricane Isabel; previously deferred fuel costs in connection with the settlement

• A $65 million after-tax charge resulting from the termination of of the Virginia jurisdictional fuel rate case, and increased two long-term power purchase agreements; nuclear refueling outage expenses at the Company's nuclear * $12 million after-tax charges associated with the restructuring generating units, partially offset by customer growth inthe of power sales contracts; electric franchise service area and a reduction in capacity * $5million after-tax severance costs associated with workforce expenses due to termination of certain long-term power reductions; and purchase agreements;

• A $21 million net after-tax loss for the cumulative effect of

• A higher contribution from Clearinghouse operations associated changes inaccounting principles, resulting from the adoption of with increased margins on settled contracts and lower net the following new accounting standards:

losses associated with the settlement of a portfolio of financial * $139 million after-tax gain-adoption of SFAS No. 143; derivatives held as economic hedges for a portion of * $101 million after-tax loss-adoption of SFAS No. 133 Dominion's'2003 natural gas production; and Implementation Issue No. C20, Interpretation of the

• A higher contribution from distribution operations, primarily Meaning of Not Clearly and Closely Related' inParagraph resulting from customer growth inthe electric franchise service 10(b) regarding Contracts with a Price Adjustment Feature; area, partially offset by comparably milder weather and an * $55 million after-tax loss-adopition of EITF 02-3; and increase in pension and other postretiremrnt benefit costs. * $4-million after-tax loss-adoption of FIN 46R.

Analysis of Consolida ad Operations Presented below are selected amounts related to the Company's results of operations:

Year Ended December 31.

2D04 203 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 Purchasedgas 110 115 Other purchased energycommodities 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 inaccounting principles (net of Income taxes) - (21) -

An analysis of the Company's results of operations for 2004

• A $49 million increase associated with new customer compared to 2003 and 2003 compared to 2002 follows: connections;

• A $24 million increase associated with comparably favorable 2004 vs. 2003 weather; and Operating Revenue

• An $18 million increase due to lost revenue in2003 as a result Regulated electric sales revenue increased 6%to $5.2 bil-of outages caused by Hurricane Isabel.

lion, primarily reflecting:

• A $231 million increase due to the impact of a comparatively Nonregulated electric sales revenue decreased 420% to a higher fuel rate on increased sales volumes. The rate increase negative $141 million, reflecting a decrease inenergy trading and resulted from the settlement of a fuel rate case inDecember marketing activities, resulting primarily from:

2003 and was more than offset by an increase inElectric fuel * $122 million of losses primarily resulting from energy trading and energy purchases, net expense and marketing activities, reflecting decreased margins in electric trading due to unfavorable price movements; and 2004/Page 13

• $142 million decline intrading revenue due to the transfer of 2003 vs. 2002 certain wholesale electric contracts to a Dominion subsidiary in Operating Revenue 2003 combined with $42 million higher margins due to Regulated electric sales revenue increased less than 1%to unfavorable price changes in2003 on those transferred $4.9 biliion, primarily reflecting the following:

wholesale electric contracts; partially offset by

• A $54 million increase representing customer growth

• A $58 million increase from the sale of excess generation and associated with new customer connections; and higher margins on electric trading.

• A $42 million increase resulting from fuel rate recoveries. Fuel Nonregulated gas sales revenue decreased 84% to $42 rate recoveries were generally offset by a comparable increase million, reflecting a decrease inenergy trading and marketing infuel expense and did not materially affect net income. These activities, resulting primarily from: increases were partially offset by:

• $130 million of losses related to certain natural gas contracts

• A $103 million decrease associated with milder weather; and held inconnection with management of storage and

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

transportation agreements; Nonregulated gas sales revenue increased 561% to $263

• A $52 million net loss associated with a portfolio of financial million, reflecting higher margins inClearinghouse gas sales, net derivatives held as economic hedges for a portion of of applicable purchases, due to favorable changes inthe fair value Dominion's 2004 natural gas production; and of derivative contracts held for trading purposes and the impact of

• A $44 million loss from comparatively lower price volatility on adopting EITF 02-3. The'increase included $54 million associated natural gas option positions. with a portfolio of financial derivatives held as economic hedges Other revenue increased 160% to $660 million, primarily for a portion of Dominion's 2003 natural gas production.

reflecting a $384 million increase in coal sales, resulting from Other revenue increased 167% to $254 million, reflecting:

higher coal prices and increased sales volumes. The increase in

• A $52 million increase in coal sales revenue; and coal sales revenue was largely offset by an increase in the cost of

• A $115 million increase resulting from a change inthe coal purchased for resale reported in Other purchased energy classification of coal purchases from other revenue to expense commodities expense. under EITF 02-3 beginning in2003.

Operating Expenses and Other Items Operating Expenses and Other Items Electric fuel and energy purchases, net expense increased Electric fuel and energy purchases, net expense increased 19% to $1.8 billion, primarily reflecting: 15% to $1.5 billion, primarily reflecting:

• A $408 million increase related to utility generation operations,

• A $123 million increase associated with nonregulated energy resulting from the combined effects of an increase inthe fixed trading operations, primarily resulting from higher volumes fuel rate and the elimination of fuel deferral accounting for the purchased and the reclassification of certain purchase Virginia jurisdiction, which resulted inthe recognition of fuel contracts due to the implementation of EITF 02-3; and expenses in excess of amounts recovered infixed fuel rates.

• A $68 million increase related to regulated operations, The increase also reflected higher generation volumes inthe including $42 million associated with rate recoveries and the current year; partially offset by recognition of $14 million of previously deferred fuel costs that

• A $130 million decrease primarily associated with the transfer of will not be recovered under the 2003 settlement of the Virginia certain wholesale electric contracts to aDominion subsidiary in2003. jurisdictional fuel rate case.

Purchased electric capacity expense decreased 9%to Purchased electric capacity expense decreased 12% to

$550 million, primarily resulting from the termination of certain $607 million, reflecting scheduled rate reductions on certain non-long-term power purchase agreements as a result of the purchase utility generation power purchase agreements ($54 million) and of the related non-utility generating facilities. lower purchases of capacity for utility operations ($30 million),

Other purchased energy commodities expense increased mesultin4 from the termination of certain long-term power purchase 174% to $518 million, primarily reflecting an increase in the cost agreements.

of coal purchased for resale. Purchased gas expense was $115 million, representing the Depreciation and amortization expense increased 8%to cost of supplies used to scrvo nonregulated gas sales.

$496 million, due to incremental expense resulting from property Other purchased energy commodities expense was $189 additions, including the consolidation of the variable interest million, reflecting the reclassification of certain purchase contracts lessor entity as a result of adopting FIN 46R at December 31, 2003. for transportation, storage and coal due to the adoption of EITF 02-3.

Other income decreased 12% to $71 million, primarily Other operations and maintenance expense rose 44% to reflecting lower net realized gains (including investment income) $13 billion, primarily reflecting the impact of the following 2003 associated with nuclear decommissioning trust fund investments. items:

Interest and related charges decreased 16% to $254 mil-

• Incremental restoration expenses associated with Hurricane lion, primarily due to refinancing of callable mortgage bonds with Isabel ($197 million);

lower cost unsecured debt in December 2003.

• 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. . The Generation segment provides electricity primarily from

• Expenses associatedwith nuclearreftilirngoutages($15 million). nuclear, coal, oil, purchased power and natural gas. Presented Depreciation and amortization expense decreased 7%to below is a summary of the system's energy output by energy

$458 million, primarily reflecting the change inthe presentation of source.

expenses associated with AROs. -

2004 2003 2002 Other taxes expense increased 14% to $173 million, t1 Nuclear i 32% 29% 32%

primarily due to the effect of a favorable resolution of sales and CoalM 38 38 42 use tax issues in 2002. Such benefits were not recognized in2003. Oil 6 6 4 Other Income increased 153% to $81 million, primarily Purchased Power, net 19 23 19 reflecting net realized gains (including investment income of $34 Natural GasrA 5 . 3 3 million) associated with nuclear decommissioning trust fund Other - 1* -

investments. Total 100% 100% 100%

Cumulative effect of changes in accounting principles- (1)Nuclear mix excludes Od Dominion Electric Cooperative's (ODEC) 11.6%

During 2003, the Company was required to adopt several new ownership interest inthe North Anna Power Station.

accounting standards, resulting ina net after-tax loss of $21 mil- (21Coal mix excludes ODECs 50% ownership interest inthe Clover Power Station.

lion, which included the following: (31Includes natural gas used incombustion turbines that ae fueled by gas.

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

Presented below, on an after-tax basis, are the key factors

• *A $101 million after-tax loss (SFAS No. 133 Implementation impacting the Generation segment's operating results:

Issue No. C20);

2004 vs. 2003

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

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

- - Decrease)

Outlook (mnillions);

The Company believes its operating businesses will provide stable Fuel expenses inexcess of rate recovery' S{115) growth in net income in2005. The following are growth factors Capacity expenses 36 that will impact these expected results: Coal trading and marketing 31

• Continued growth inutility customers: and Customer growth 20

• Reduced electric capacity expenses, resulting from the "Weather 10 termination of long-term power purchase agreements. Interest expense 9 Lost revenue due to Hurricane Isabel 7 The growth factors in 2005 will be impacted by: Other 3

• Higher expected Virginia jurisdictional fue! expenses: and Change Innet income contribution S 1

• Increased interest expense.

Based on these projections, the Company estimates that cash ' Generation's net income increased $1miIlion, primarily reflecting flows from operations will increase in2005, as compared to 2004. the following:

Management believes this increase will provide sufficient cash

• Higher fuel expenses due to the eliminaion of fuel deferral flows to maintain or grow ths Company's current dividend to accounting for the Virginia jurisdiction, which resulted inthe Dominion. recognition of fuel expenses in excess of amounts recovered in

-Segment Results of Operations 'fixed fuel rates. The increase infuel expenses also reflects higher generation volumes; Generation

• Reduced purchased power capacity expenses due to the Generation includes the Companys portfolio of e!ectric generating termination of certain long-term power purchase agreements in facilities, power purchase agreements, marketing of its excess connection with the purchase of the related non-utility generation resources and coal trading and marketing activities. generating facilities; Year Ended December 31,

• A higher contribution from coal trading and marketing. primarily 2004 2003 2002 due to higher coal prices and increased sales volumes; (millions)

Net Income contribution $407 $406 $486 Electricity supplied (million mwhrs) 79 76 76 mmwhrs = megawatt hours 2004/Page 15

• An increase inregulated electric sales revenue due to customer Presented below, on an after-tax basis, are the key factors growth in the electric franchise service area, primarily in impacting the Energy segment's operating results:

residential and commercial customer connections;

• An increase inregulated electric sales revenue from 2004 vs 2003 comparably favorable weather; Increase

• Lower interest expense due to refinancing of callable mortgage (Decrease) bonds with lower cost unsecured debt inDecember 2003; (millions)

• An increase inregulated electric sales revenue due to lost Energy trading and marketing activities S(184) revenue in2003 associated with outages related to Hurricane Economic hedges (12)

Isabel; and Electric transmission revenue (15)

• Other factors including the impact of economic conditions on Other 2 customer usage. Change innet Income contribution $(209) 2003 vs. 2002 Energy had a net loss of $109 million in 2004, as compared to net income of $100 million in2003, primarily reflecting:

• A net loss from energy trading and marketing activities, (millions) resulting primarily from the effects of unfavorable price Revenue reallocation 5(57) changes on electric trading margins, the transfer of certain Weather (42) wholesale electric contracts to a Dominion subsidiary in 2003 Capacity expenses 29 and comparatively lower price volatility on natural gas option Customer growth 22 positions; Utility outages (11)

• A decrease attributable to unfavorable price movements Fuel rate case settlement (9)

Other (12) associated with a portfolio of financial derivatives held as economic hedges for a portion of Dominion's 2004 natural gas Change innet income contribution 1(80) production; and

• Lower electric transmission revenue, primarily due to Generation had a decrease of $80 million innet income, primarily decreased wheeling revenue resulting from lower contractual reflecting the following:

volumes and unfavorable market conditions.

• A change inthe allocation of electric base rate revenue among the Generation, Energy and Delivery segments effective 2003 vs. 2002 January 1,2003;

- Increase

• A decrease in regulated electric sales due to comparably (DXecrease) unfavorable weather. (millionsl

• Scheduled decreases incapacity expenses under certain long-Economic hedges $33 term power purchase agreements; Energy trading and marketing activities 21

• An increase inregulated electric sales due to customer growth Electric transmission margins 11 in the electric franchise service area, primarily reflecting an Revenue reallocation 7 increase innew residential customers; Change innet income contribution $72

• Increased outage expenses, reflecting refueling outagas in 2003 at the Company's nuclear generating units; and Energy's net income contribution increased $72 million, primarily

• Recognition of previously deferred fuel costs in connection with reflecting:

the 2003 Virginia rate settlement.

• Lower net losses associated with a portfolio of financial Energy derivatives held by the Clearinghouse held as economic hedges Energy includes the Company's electric transmission and energy on behalf of Dominion inconnection with price risk trading and marketing operations. management for a portion of its future sales of natural gas production; Year Ended Decemter 31,

• An increose inthe contribution of energy trading and marketing 2004 2003 2002 activities, reflecting increased margins on settled contracts, (millions) partially offset by a decrease innet mark-to-market gains on Net Income (loss) $1109) $100 $28 derivative contracts;

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

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

2004/Page 16

Delivery . *'A decrease inregulated electric sales due to comparably milder Delivery includes the Company's electric distribution system and weather; '

customer service operations.

• An increase inregulated electric sales due to customer growth inthe electric franchise service area, primarily reflecting new Year Ended December 31, residential customers; and 2004 203 2002

• Other factors, including an increase inpension and other (millions) postretirement benefit costs.

Net Income contribution *288 $282 $255 Electricity delivered to utility customers (million mwhrs) 78 75 75 Corporate and Other Corporate and Other includes the Company's corporate and other Presented below, on an after-tax basis, are the key factors functions and specific items.

impacting the Delivery segment's operating results: Presented below are the Corporate and Other segment's after-2004 vs. 2003 tax operating results:

Increase Year Ended Decemer 31, (Decreasei 2004 2003 2002 (millions) (millions)

Interest expense $14 Cumulative effect of changes in Reliability expenses (11) accounting principles $- $ (21) S-Customer growth 9 Specific Items attributable to operating Weather .4 I segments (155) (204) 4 Other (10) Other - (2) -

Change innet income contribution $6 Nei Income (loss) $(155) $(227) $4 Delivery's net income contribution increased $6million, reflecting: 2004

• Lower interest expense due primarily to refinancing cf callable The Company reported inthe Corporate and Other segment (in mortgage bonds with lower cost unsecured debt in Decemter other operations and maintenance expense) the following specific 2003; items attributable to its operating segments:

• Higher reliability expenses, primarily due to increased tree

• A $184 million ($112 million 'after-tax) charge related to the trimming: valuation of the Company's interest ina long-term power

• An increase in regulated electric sales revenue due to customer tolling contract (Generation);

growth in the electric franchise service area, primarily * $71 million ($43 million after-tax) of losses from the termination refledting new residential customers; of three long-term power purchase agreements (Generation);

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

• A $12 million ($7 million after-tax) charge related to an

• Other factors, including an increase inpension expense. agreement to settle a class action lawsuit involving a dispute over the Company's rights to lease fiber-optic cable along a 2003 vs. 2002 portion of its electric transmission corridor (Energy); partially Increase offset by (Decrease) *-;An $18 million ($11 million after-tax) benefit to adjust expenses (millions) accrued in2003 associated with restoration activities related to Revenue reallocation S50 Hurricane Isabel (Delivery).

Weather (19)

Customergrowth 10 2003 Other (14) The Company reported inthe Corporate and Other segment (in other operations and maintenance expense) the following specific Change Innet Income contribution $27 items attributable to its operating segments:

Delivery's net income contribution increased $27 million, reflect-

• A $21 million net after-tax loss for the cumulative effect of ing: changes inaccounting principles, resulting from the adoption of

• A change inthe allocation of electric base rate revenue among the following new accounting standards:

the operating segments effective January 1,2003; * $139 million after-tax gain-adoption of SFAS No. 143

($140 million after-tax gain-Generation and $1million after-tax loss-Delivery);

2004/Page 17

• $101 million after-tax loss-adoption of Statement 133 optimization of company assets will be reported as part of the Implementation Issue No. C20 (Generation); results of the business segments operating the related assets.

• $55 million after-tax loss-adoption of EITF 02-3 (Energy); A summary of the changes inthe unrealized gains and losses and recognized for the Company's energy-related derivative instru-

• $4million after-tax loss-adoption of FIN 46R (Generation). ments held for trading purposes during 2004 follows:

• $197 million ($122 million after-tax) of incremental restoration Amount expenses associated with Hurricane Isabel: $119 million (millions)

(Delivery), $2million (Energy) and $1million (Generation):

• A $105 million ($65 million after-tax) charge resulting from the Net unrealized loss at December 31, 2003 S(45)

Contracts realized or otherwise settled during the period 52 termination of two long-term power purchase agreements Net unrealized gain at inception of contracts initiated (Generationt during the period

• $21 million ($12 million after-tax) of charges associated with Other changes infair value (42) the restructuring of power sales contracts (Generation); and Changes invaluation techniques

• $8million ($5 million after-tax) of severance costs associated Net unrealized loss at December 31, 2004 $(35) with workforce reductions: $5million (Delivery) and $3million (Generation).

The balance of net unrealized gains and losses recognized for the Company's energy-related derivative instruments held for Selected Information-Energy Trading Activities trading purposes, at December 31, 2004, issummarized in the As previously described, the Company manages its energy trading following table based on the approach used to determine fair value and risk management activities through the Clearinghouse. The and contract settlement or delivery dates:

Company believes these operations complement its integrated Maturity Based on Contract Settlement energy businesses and facilitate its risk management activities. As or Delivery Date(s) part of these operations, the Clearinghouse enters into contracts Less In Excess for purchases and sales of energy-related commodities, including Than 1-2 2-3 3-5 of5 Source of Fair Value 1 Year Years Years Years Years Total coal, natural gas and oil. During 2003 and prior periods, the Company's Clearinghouse operations also included contracts for Imillions) purchases and sales of electricity. Inconnection with Dominion's Activelyquotedlll $(27) S (1) $ 5 $- - $(23) plan to conduct its non-utility wholesale electric marketing and Other external trading activities through another Dominion subsidiary, the sourcesr- (7) (7) 2 - (12)

Models and other Company assigned certain wholesale electric contracts that are valuation methodsm _ _ _ _

not supplied from its own generation resources and involve activ-ities outside of its service territory. The Company will continue to Total 5(27) $ (8) S(2) $ 2 - $(35) market its generation resources not needed to serve utility (1)Exchange-traded and over-the-counter contacts.

customers but will do so as part of its management of utility (2)Values based on prices from over-the-cunter broker actity and industry serv-system resources inthe Generation segment rather than through ices and, where applicable. conventional option pticing models.

its Clearinghouse operations. (3)Values based on the Companys estimate of future commodity prices when Settlement of a contract may require physical delivery of the information from exterrral sources isnot available and use of internally-developed models, reflecting option pricing theory, discounted cash flow underlying commodity or cash settlement. The Clearinghouse concepts, etc.

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 typ caliy enters into a sales con-Sources and Uses ofCash tract, or a combination of sales contracts, with quantities and The Company depends on both internal and external sources of delivery or settlement terms that are identical or very similar to liquidity to provide working capital and to fund capital require-those of the purchase contract When the purchase and sales ments. Short-term cash requirements not met by cash provided by contracts are settled either by physical delivery of the underlying operating activities are generally satisfied with proceeds from commodity or by net cash settlement, the Clearinghouse may short-term borrowings. Long-term cash needs are met through receive a net cash margin (arealized gain), or may pay a net cash sales of securities and additional long-term financing.

margin (arealized loss). Clearinghouse management continually At December 31, 2004, the Company had cash and cash equiv-monitors its contract positions, considering location and timing of alents of $2million with $1.5 billion of unused capacity under its delivery or settlement for each energy commodity in relation to credit facilities. For long-term financing needs, amounts available market price activity, seeking arbitrage opportunities. for debt or equity offerings under currently effective shelf registra-During the fourth quarter of 2004, the Company performed an tions totaled $670 million at February 1,2005.

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. Begin-ning in 2005, all revenue and expenses from the Clearinghouse's 2004/Page 18

Operating Cash Flows ,. . *,, o C.as five largest crunterparty exposures, combined, for this category represented As presented on the Companys Consolidated Stateinents of Cash approximately 22% of the total gross credit exposure.

(21The five largest counterpart exposures. combined, for this category, repre-Flows, net cash flows from operating activities were $1.2 billion in sented less than 1%of the total gross credit exposure.

2004, $1.2 billion in 2003 and $1.3 billion in2002. Management 131The five largest counterparty exposures, combined, for this category, repre-believes that its operations provide a stable source of cash flow sented approximately 26% of the total gross credit exposure.

sufficient to contribute to planned levels of capital expenditures (41The five largest counterparty exposures. combined, for this category, repre-sented approximately 2%of the total gross credit exposure.

and maintain or grow current dividends payable to Dominion.

The Company's operations are subject to risks and Investing Cash Flows uncertainties that may negatively impact the timing or amounts of During 2004, 2003 and 2002, the Company's investing activities operating cash flows, including: resulted innet cash outflows of $876 million, $1.1 billion and $857

• Cost-recovery shortfalls due to capped base and fuel rates in million, respectively. Significant investing activities for 2004 effect inVirginia for the utility generation business; included $96 million for nuclear fuel expenditures and $761 million

• Unusual weather and its effect on energy sales to customers for plant construction and other property additions detailed as and energy commodity prices; follows:.

• Extreme weather events that could disrupt or cause * $327 million on generation-related projects, including catastrophic damage to the Company's electric distribution and environmental upgrades and routine capital improvements; transmission systems; * $122 million on transmission-related projects, reflecting

• Exposure to unanticipated changes inprices for energy- construction and improvements; commodities purchased or sold, including the effect on * $286 million on distribution-related projects, reflecting routine derivative instruments that may require the use of funds to post capital improvements and expenditures associated with new margin deposits with counterparties; connections; and

• Effectiveness of the Company's risk management activities and * $26 million for other general and information technology underlying assessment of market conditions and related projects.

factors, including energy commodity prices, basis, liquidity, Investing activities for 2004 also included $277 million for volatility, counterparty credit risk, availability of generation and purchases of securities and $237 million from sales of securities transmission capacity, currency exchange rates and interest related to investments held inthe Company's nuclear decom-rates; missioning trusts.

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

• Contractual or regulatury restrictions on transfers of funds The Company relies on access to bank and capital markets as a among the Company and Dominion and its subsidiaries. significant source of funding for capital requirements not satisfied by the cash provided by the Company's operations, As discussed in Credit Risk - the Credit Ratings below, the Company's ability to borrow funds or The Company's exposure to potential concentrations of credit risk issue securities and the return demanded by investors are affected results primarily from its energy trading and risk management by the Company's credit ratings. Inaddition, the raising of external activities. Presented below isa summary of the Company's gross capital is subject to certain regulatory approvals, including author-and net credit exposure as of December 31, 2004 for these activ- ization by the Virginia State Corporation Commission (Virginia ities. The Company calculates its gross credit exposure for each Commission).

counterparty as the unrealized fair value of derivative contracts During 2004, 2003 and 2002, net cash flows used infinancing plus any outstanding receivables (net of payables, where netting activities were $338 million, $160 million and $367 million, agreements exist), prior to the application of collateral. respectively.

December31, 24, JointCredit Facilities and Short-Term Debt Gross * .I Net . The Company's financial policy precludes issuing commercial Credit Credit Credit paper inexcess of its supporting lines of credit Dominion, Con-

• Exposure Collateral . Exixosne solidated Natural Gas Company (CNG), a wholly-owned subsidiary (millions) of Dominion, and the Company have two three-year revolving joint Investment graded $425 $17 . $408 Non-investment gradem . 2 1 1 credit facilities that allow aggregate borrowings of up to $2.25 No external ratings: - billion. The Company is required to pay minimal annual commit-Internally rated-investment ment fees to maintain the joint credit facilities. The facilities graded' 249 - 249 include a $1.5 billion credit facility that was entered into inMay Internally rated-non-investment grade) . . 19 - 19 2004 and terminates inMay 2007 and a $750 million credit facility Total $695 $18 $677 that was entered into in May 2002 and terminates inMay 2005. It is expected that the $750 million credit facility will be renewed 111Designations as investment grade are based on minimum credit ratings prior to its maturity. These credit facilities are being used for assigned by Moodys Investors Service (Moodys) and Standard &Poor's Rating working capital, as support for the combined commercial paper Group, adivision of the McGraw-Hill companies, Inc. (Standard &Poors). The 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 In2004, the Company repaid $250 million of its 8%mortgage facility and $200 million under the $750 million credit facility. At bonds due March 1, 2004 and $75 million of its 7.2% senior notes December 31. 2004, capacity available under the two credit facili- due November 1,2004.

ties was $1.5 billion.

Common Stock Both joint credit agreements contain various terms and con-In 2004, the Company issued 20,115 shares of its common stock to ditions that could affect the Company's ability to borrow funds Dominion for cash consideration of $500 million. The Company under these facilities, accelerate repayment of any outstanding used the proceeds in part to pay down its $345 million affiliated Company borrowings or possibly result in the termination of the short-term demand note from Dominion.

commitment to lend funds to the Company. These terms and con-In2004 and 2003, the Company recorded $11 million and $21 ditions include maximum debt to total capital ratios, cross-default million, respectively, of additional paid-in capital in connection provisions and material adverse change clauses. Although the joint with the reduction inamounts payable to Dominion.

credit agreements contain material adverse change clauses, the participating lenders, under those specific provisions, cannot Borrowings from Parent refuse to advance funds to the Company for the repurchase of its At December 31, 2004, an unregulated subsidiary of the Company outstanding commercial paper. had borrowed funds from Dominion totaling $645 million under a The ratio of the Company's debt to total capital, as defined by short-term demand note. At December 31, 2004, the Company had the agreements, should not exceed 60% at the end of any fiscal outstanding borrowings from Dominion of $220 million under a quarter. As of December 31, 2004, the Company's calculated debt long-term note. Interest charges incurred by the Company related to total capital ratio was 50%. Under the agreements' cross- to these borrowings were $11 million in 2004. Interest charges default provisions, if the Company or any of its material sub- incurred in2003 were not material.

sidiaries fail to make payment on various debt obligations in Amounts Available under Shelf Registrations excess of $25 million, the lenders could require the Company to At February 1,2005, the Company had approximately $670 million accelerate its repayment of any outstanding borrowings under the of available capacity under currently effective shelf registrations.

credit facility and the lenders could terminate their commitment to The shelf registrations would permit the Company to issue debt lend funds to the Company. However, any defaults on indebted-ness by Dominion, CNG or any material subsidiaries of those affili- and preferred securities to meet future capital requirements.

ates would not affect the lenders' commitment to the Company Credit Ratings under the joint credit agreements. Credit ratings are intended to provide banks and capital market At December 31, 2004, total outstanding commercial paper participants with a framework for comparing the credit quality of supported by the joint credit facilities was $573 million, of which a securities and are not a recommendation to buy, sell or hold secu-total of $267 million was the Company's borrowings, with a rities. Management believes that the current credit ratingsnf the weighted average interest rate of 2.35%. Commercial paper Company provide sufficient access to the capital markets. How-borrowings are used primarily to fund working capital require- ever, disruptions inthe banking and capital markets not specifi-ments, as a bridge to long-term debt financing and may vary sig- cally related to the Company may affect the Company's ability to nificantly during the course of the year, depending upon the timing access these funding sources or cause an increase in the return and amount of cash requirements not satisfied by cash provided by required by investors.

operations. Both quantitative (financial strength) and qualitative (business At December 31, 2004, total outstanding letters of credit or operating characteristics) factors are considered by the credit supported by the joint credit facilities were $183 million, of which rating agencies in establishing the Company's credit ratings. Credit a total of $104 million was issued on behalf of an unregulated ratings should be evaluated independently and are subject~to subsidiary of the Company. revision or withdrawal at any time by the assigning rating orga-nization. The cred:t ratings fi; the Ccmp3ny are most affected by .

Long-Term Debt InAugust 2004, in connection with the acquisition of a generating the Company's financial profile, mix of regulated and non-regulated businesses and respective cash flows, changes in, facility, the Company assumed $109 million of private placement methodologies used by the rating agencies and 'event risk," if bonds and $25 million of pollution control bonds. InNovember applicable.

2004, the Company exchanged $106 million of its 2004 Series A 7.25% senior notes due 2017 (the senior notes) for the outstanding Credit ratings for the Company as of February 1,2005 follow.

private placement bonds, following the scheduled principal Stardard payment of $3million. The senior notes have the same financial &PoOrs ?Moodycs terms as the private placement bonds, but are registered secu- Mortgage bonds A- A2 rities. Inaddition, inNovember 2004, the Company assumed $79 Senior unsecured (including tax-exempt) million of industrial development bonds issued by Pittsylvania debt securities BBB+ A3 County, VA as part of the acquisition of another non-utility Preferred securities of affiliated trust BBB- Baal generating facility. Preferred stock BBB- Baa2 Commercial paper A-2 P-1 2004/ Page 20

As of February 1.2005, Standard & Poor's maintains a negative excludes all amounts classified as current liabilities on the Con-outlook for its ratings of the Company.  ; solidated Balance Sheets;'other than current maturities of long-Generally, a downgrade inthe Company's credit rating would term debt and interest payable. The majority of current liabilities not restrict its ability to raise short-term or long-term financing so will be paid incash in2005.

long as its credit rating remains 'investment grade,' but it would LessThan 1-3 3-5 MoreThan increase the cost of borrowing. The Company works closely with 1Year Years Years 5Years Total both Standard & Poor's and Moody's with the objective of main- (millions) taining the Company's current credit ratings. As discussed inRisk Long-term debtS1 $ 12 $1,876 S 408 $2,666 $ 4,962 Factorsand Cautionary Statements That MayAffect Future Interest payments'2 265 484 324 2,289 3,362 Results, in order to maintain its current ratings, the Company may Leases 36 45 26 29 136 find it necessary to modify its business plans and such changes Purchase obligationsr3 :

may adversely affect its growth. Purchased electric capacity for utility Debt Covenants operations 509 968 858 3,103 5,438 As part of borrowing funds and issuing debt (both short-term and Fuel used for utility long-term) or preferred securities, the Company must enter Into operations 691 673 245 51 1,660 enabling agreements. These agreements contain covenants that, in Energy commodity the event of default, could result in the acceleration of principal purchases for resale( 4 ) 422 21 2 - 445 and interest payments; restrictions on distributions related to its Other 28 6 - - 34 capital stock to Dominion, including dividends, redemptions, Other long-term repurchases, liquidation payments or guarantee payments; and, in liabilities' some cases, the termination of credit commitments unless a Financial derivative-waiver of such requirements is agreed to by the lenders/security commodities(I 233 39 - - 272 holders: These provisions are customary, with each agreement Other contractual

. obligations 1 11 2 - . 14 specifying which covenants apply. These provisions are not neces-sarily unique to the Company. Some of the typical covenants Totalcashpayments $2.197 $4,123 $1,865 $8,138 $16,323 include:

(1)Based on stated maturity dates rather than the earlier redemption dates that

• The timely payment of principal and interest; could be elected by instrument holders.

• Information requirementsincluding submitting financial reports (21Does not reflect the companys ability to defer distributions related to its junior filed with the Securities and Exchange Commission to lenders; subordinated notes payable to affiliated trust

• Performance obligations, audits/inspections, continuation of (3)Amounts excluds open purchase orders for services that are provided on demand, the timing of which cannot be Jetermined.

the basic nature of business, restrictions on certain matters (41Represents the summation of settlement amounts, by contracts, due from the related to marger or consolidation, restrictions on disposition of Company it all physical or financial transactions among the Company and its substantial assets; counterparties were liquidated and terminated.

• Compliance with collateral minimums or requirements related (51Excludes 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 to mortgage bonds, and the Consolidated Financial Statements. Deferred income taxes are also

• Limitations on liens. excluded since cash payments are based primarily on taxable income for each discrete fiscal year.

The Company monitors the covenants on a regular basis in order to ensure that events of default will not occur. As of Planned Capital Expenditures December 31, 2004; there were no events of default under the The Company's planned capital expenditures during 2005 are Company's covenants. expected to total approximately $870 million, which includes the cost of acquiring certain non-utility generating facilities. InFebruary Future Cash Payments for Contractual Obligations and 2005, the Company completed the termination of a long4lerm power Planned Capital Expenditures purchase agreement and acquisition of the related generating Contractual Obligations facility used by Panda-Rosemary P,a non-utility generator, to pro-The Company is party to numerous contracts and arrangements vide electricity to the Company. See Restructudng of Contract with obligating the Company to make cash payments infuture years. Non-Utility Generator under Future Issues and Other Matters. For These contracts include financing arrangements such as debt 2006, planned capital expenditures are expected to be approximately agreements and leases, as well as contracts for the purchase ot $900 million. Included inthe Company's total planned capital goods and services and financial derivatives. Presented below is a expenditures are the following:

table summarizing cash payments that may result from contracts to Capacity which the Company is a party as of December 31, 2004. For pur- Based on available generation capacity and current estimates of chase obligations and other liabilities, amounts are based upon growth incustomer demand, the Company will likely need addi-contract terms, including fixed and minimum quantities to be tional baseload generation inthe future. However, the Company purchased at fixed or market-based prices. Actual cash payments currently has no definite plans to build any new baseload will be based upon actual quantities purchased and prices paid generating units in the near-term. As part of the Company's and will likely differ from amounts presented below. The table ongoing generation supply strategy, the Company continues to 2004/Page21

evaluate the development of new baseload plants to meet sition period. and the Companycould realie the negative, customer demand for additional generation needs inthe future. - economnic impact of any such'6dverse'event. Conversely, the, Through 2007. ths Company will continue to meet any additional Company may experience a positive economic impact to the extent capacity and energy requirements through market purchases. that it can reduce its fuel factor-related costs for its electric utility Plant and Equipment generation-related operations. . ' '

The Company's annual capital expenditures for plant and equip' Other amendments to the Virginia Restructuring Act were also ment for 2005, including environmental upgrades and coistruction enacted with respect to aminimum stay exemption program, a improvements. are expected to total approximately as follows:' wires charges exerription program and allowing the development..

• Generation and nuclear fuel: $400 million includes the cost of of acoal-fired generating piant in southwest Virginia for serving acquiring certain non-utility generating facilities;' default service needs. Underthe minimum stay exemption pro-

• Transmission: $120 million; and gram, large cusiomers with a load of 500 kW or greater would be

• Distribution: $350 million primarily provides for customer exempt from the twelve month minimiuim stay obligation under growth, reliability initiatives and routine replacements. capped rates if they return to supply service from the incumbent utility at market-based pricing after they have switched to supply.

service with acompetitive service provider. The wires charge' Future Issues and Other Matters exemption program would allow large industrial and commercial Status of Deregulation in Virginia customers, as well as aggregated customers in all rate classes; to The Virginia Electric Utility Restructuring Act (Virginia' avoid paying wires charges by agreeing to market-based pricing Restructuring Act) was enacted in 1999 and established a plan to - upon return to the incumbent electric utility. InJanuary 2005. the' restructure the electric utility industry inViriginia. The Virginia Company filed compliance plans for both of these programs.

Restructuring Act addressed among other things: capped base RTO ' I* !i'... . , .. ., ,;

rates, regional transmission organization (RTO) participation, retail InSeptember 2002, the Compariy and PJM lntdrconnectidn, LLC choice, the recovery of stranded costs and the functional separa- (PJM) entered into an agreement that provides for, subject to tion of a utility's electric generation from its electric transmission- regulatory approval and certain 'rovisions, the Company to and distribution operations. become, amembertf PJM, transfer functional control of its electric Retail choice has been available to all of the Company's transmission'facilitiei to PJM for inclusion ina new PJM South Virginia regulated electric customers since January 1,2003. The " Region and integrate its control area into the PJMenergy'markets.,

Company has also separated its generation, distribution and The agreement also allocates costs of implementation of the.,

transmission functions through the creation of divisions. Virginia agreement amo'ng the partes. '.,

codes of conduct ensure that Virginia Power's generation and' InOctober 2004, the FERC issued an order conditionally other'divisions operate independently and prevent crdss-subsidies approving the Company's application to join PJM. Inits order.,

between the generation and other divisions'. FERC determined that (i)the Company's prooosed transmission, Since the passage of the Virginia Restructuring Act, the come rate tieatment must conform to a regional transmission rate' petitive environment has not developed inVirginia as anticipated., design, and (ii)the Company must assess all available evidence InApril 2004, the Governor of Virginia signed into law amend-; and deterimine whether the requested def6rral of eiperd-tures ments to the Virginia Restructuring Act and the Virginia fuel factor related to the establishment and operation of an RTO sliould be statute. The amendments extend capped base rates to recorded as a'regulatory asset until the end of the Virginia retail December 31. 2010, unless moditied or terminated earlier under rate cap period. Inaseparate order issued idSeptember 2004, the Virginia Restructuring Act Inaddition to extending capped: FERC granted authority to the Company and its affiliates with i rates, the amendments: market based rate authority to charge niarket based rates for sales.

• Lock in the Company's fuel factor provisions until the earlier of of'elec'ric energy and capacity to moads located within the Compa-July 1,2007 or the terminatioin of capped rates-; .

ny'sservice territory upon its integration into PJM:

• Provide for a one-time adjustment of the Company's fuel factor, The CompanyIya! nmade filings with both the Virginia Commis-effective July 1,2007 through December31, 2010 (unless, sion' and North Carolina Utilities Commission (North Carolina capped rates are terminated 'earlier under the Virginia Coi~rnission) requesting authorization to become a member of"'

Restructuring Act), with no adjustment for previously incurred PJM. InOctober 2004, the Company filed a settlement agreemeint over-recovery or under-recovery, thus'eliminating deferred fuel with the Virginia Crmmission resolving 'most of the issiues raised.

accounting for the Virginia jurisdiction; and by interested partesin the proceeding, and hearings were held to

• End wires charges on the earlier of July 1,2007cr the address the remaining issues. The Virginia Commission approved' termination of capped rates, consistent with the Virginia -

the Companys application to join PJM inNovember 2004 subject Restructuring Act's original timetable.

to the terms and'conditions of the settlement agreement The The risk of fuel factor-related cost recovery shortfalls may also North Carolina Commission evidentiary hearing was held inJan-adversely impact the Companys cost structure during the tran-' -: uary 2005. The Company cannot predict the outcome of this matter at this time.

2004/ Page 22

North Carolina Rate Matter competitive market structure inVirginia and the expiration or Inconnection with the North Carolina Commission's approval of termination of capped rates and wires charges, the Company may the CNG acquisition, the Company agreed not to request an have to reevaluate its utility generation assets for impairment and increase inNorth Carolina retail electric base rates before 2006, long-term power purchase agreements for potential losses.

except for certain events that would have a significant financial Assumptions about future market prices for electricity represent a impact on the Company's utility operations. Fuel rates are still critical factor that affects the results of such evaluations. Since subject to change under the annual fuel cost adjustment proceed- 1999, market prices for electricity have fluctuated significantly and ings. However, inApril 2004, the North Carolina Commission will continue to be subject to volatility. Any such review inthe commenced an investigation into the Company's North Carolina future, which would be highly dependent on assumptions consid-base rates and subsequently ordered the Company to file a general ered appropriate at the time, could possibly result in the recog-rate case to show cause why its North Carolina base rates should nition of plant impairment or contract losses that would be not be reduced. The rate case was filed inSeptember 2004, and in material to the Company's results of operations or its financial February 2005, the Company reached a tentative settlement with position.

parties in the case that issubject to North Carolina Commission Changes to Cost Structure-In April 2004, the Governor of approval before becoming effective. Virginia signed into law amendments to the Virginia Restructuring Recovery of Stranded Costs Act and the Virginia fuel factor statute. The amendments extend Stranded costs are those generation-related costs incurred or capped base rates until December 31, 2010, unless capped rates are terminated earlier under the Virginia Restructuring Act. The commitments made by utilities under cost-basei regulation that generation-related cash flows provided by the Virginia may not reasonably be expected to be recovered in a competitive market. At December 31, 2004, the Companys exposure to poten- Restructuring Act are intended to compensate the Company for tially stranded costs included long-term power purchase contracts continuing to provide generation services and to allow the Com-pany to incur costs to restructure such operations during the tran-that could ultimately be determined to be above market sition period. As a result, during the transition period, the generating plants that could possiblybecdme uneconomical ina Company's earnings may increase to the extent that it can reduce deregulated environment and unfunded'obligations for nuclear operating costs for its utility generation-related operations. Con-plant decommissioning and postretirement benefits not yet recog-versely, the same risks affecting the recovery of the Company's nized inthe financial statements. The Company believes capped stranded costs, discussed above. may also adversely impact its electric retail rates and, where applicable, wires charges will provide an opportunity to recover a porion of its potentially cost structure during the transition period. Accordingly, the

-stranded costs, depending on market prices of electricity and other Company could realize the negative economic impact of any such factors. Recovery of the Company's potentially.stranded costs adverse event. Inaddition to managing the cost of its generation-related operations, the Company may also seek opportunities to remains subject to numerous risks even inthe'capped-rate environment. These include, among others~exposure to long-term sell available electric energy and capacity to customers beyond its power purchase commitment losses, future environmental coin-. electric utility service territory. Using cash flows from operations during the transition period, the Company may further alter its cost pliance requirements, changes intax laws nuclear:

structure or choose to make additional investments inits business.

decommissioning costs, inflation, increased capital costs and The capped rates were derived from rates established as part recovery of certain other items.

of the 1998 Virginia rate settlement and do not provide for specific The enactment of deregulation legislati6n in1999 not only caused the discontinuance of SFAS No. 71. Accounting for the recovery of particular generation-related expenditures, except for certain regulatory'assets. To the extent that the Company manages Effects of Certain Types of Regulatio'n for the CompariYs Virginia jurisdictional utility generation-related operations but also caused its operations to reduce its overall operating costs below those levels included inthe capped rates, the Company's earnings may the Company to review its utility generation assets for impairment increase. Since the enactment of the Virginia Restructuring Act, and long-term power purchase agreemeots Jor potential losses. at the Company has been reviewing its cost structure to identify that time. Significam: assumptions considered inthat review .

included possible futurermarket prices for fuel and electricity, load, opportunities to reduce the annual operating expenses of its generation-related operations in the period 2001 through 2004, growth, generating unit availability and future capacity additions in the Company negotiated the termination of several long-term the Company's market, capital expenditures, including those power purchase agreements that is expected to reduce capacity related to environmental improvements, and decommissioning activities. Based on those analyses, no recognition of plant. payments in2005 by $179 million.

impairments or contract losses was appropriate at that tirne. In Environmental Matters response to future events resulting from the development of a 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 20041Pagse23

increased capital, operating and other costs as a result of corn- Future Environmental Regulations pliance, remediation, containment and monitoring obligations. inJanuary 2004, the EPA proposed additional regulations Historically, the Company recovered such costs arising from regu- addressing pollution transport from electric generating units as lated electric operations through utility rates. However, to the well as the regulation of mercury and nickel emissions. These extent that environmental costs are incurred in connection with regulatory actions, in addition to revised regulations to address operations regulated by the Virginia Commission, during the period regional haze, are expected to be finalized in2005 and could ending December 31, 2010. inexcess of the level currently require additional reductions in emissions from the Company's included inthe Virginia jurisdictional electric retail rates, the fossil fuel-fired generating facilities. If these new emission reduc-Company's results of operations will decrease. After that date, tion requirements are imposed, significant additional expenditures recovery through regulated rates may be sought for only those may be required.

environmental costs related to regulated electric transmission and The U.S. Congress is considering various legislative proposals distribution operations and recovery, if any, through the generation that would require generating facilities to comply with more strin-component of rates will be dependent upon the market price of gent air emissions standards. Emission reduction requirements electricity. under consideration would be phased in under a variety of periods of up to 15 years. If these new proposals are adopted, additional Emvironmenta! PrDtOction and Monitoring Expenditures significant expenditures may be required.

The Company incurred app.oximate!y $115 mii'ion, 100 million In 1997, the United States signed an international Protocol to and $117 million of expenses (including dep eciaticn) dLring 2004, limit man-nmade greenhouse emissions under the United Nations 2003 and 2002, respectively, inconnection with environmental Fra.mework Convention on Climate Change. However, the Protocol protection and monitoring activities and expects these expenses to will not become binding unless approved by the U.S. Senate.

be approximately $124 million in2005 and $136 million in 2006. In Currently, the Bush Administration has indicated that it will not addition, capital expenditures related to environmental controls pursue ratification of the Protocol and has set a voluntary goal of were $84 million, $197 million and $214 million for 2004, 2003 and reducing the nation's greenhouse gas emission intensity by 18%

2002, respectively. These expenditures are expected to be approx-over the next 10 years. Several legislative proposals that include imately $28 million for 2005 and $126 million for 2006.

provisions seeking to impose mandatory reductions of greenhouse CleannAirAct Compliance gas emissions are under consideration in the United States Con-The Clean Air Act requires the Company to reduce its emissions of gress. The cost of compliance with the Protocol or other mandatory sulfur dioxide (SO 2) and nitrogen oxide (NOJ. which are gaseous greenhouso gas reduction obligations could be significant. Given by-products of fossil fuel combustion. The Clean Air Act's SO2 and the highly uncertain outcome and timing of future action, if any, by NOx reduction programs include: the U.S. federal government on this ;ssue, the Company cannot

• The issuance of a limited number of SO 2 emission allowances. predict the financial impact of future climate change actions on its Each allowance permits the emission of one ton of SO 2 into the operations at this time.

atmosphere. The allowances may be transacted with a third NuclearrInsurance party, and The Price-Anderson Act expired inAugust 2002, but operating

• NOx emission limitations applicable during the ozone season nuclear reactors continLe to be covered by the law, wtich would months from May through September and on an annual channel and cap claims if a nuclear accident should occur. The.

average basis.

Price-Anderson Act vwas first enacted in 1957 and has been Implementation of projects to comply with SO 2 and NOx limi- rengwed three times since 1967. Congress iscurrently holding tations are ongoing and will be influenced by changes inthe regu- hearings to reauthcrze the legislation.

latory environment, availability of allowances, %variousstate and federal control programs and emission control technology. In Other Matters response to these requirements, the Company estimates it will RestrrhWring of Cnntract with Non-Utility Generator make capital expenditures at its affected generating facilities of In February 2005,.the Ccmpany paid $42 million incashkand approximately $455 million during the period 2005 through 2009 assumed $62 million of debt in connection with the termination of for SO%and NO, emission control equipment. a long-term power purchase Fgreement and acquisition of the Other EPA Matters related generating facility used by Panda-Rosemary LP, a non-In relation to a Notice of Violation received by the Company in utility generator, to provide electricity to the Company. The trans-2000 from the Environmental Protection Agency (EPA), the Com- action is part of an ongoing program that seeks to achieve pany entered into a Consent Decree settlement in 2003 and competitive cost structures of the Company's utility generation committed to improve air quality. The Company has already business and is expected to reduce annual capacity payments by incurred certain capital expenditures fo. environmental improve- $18 million. The purchase price for the acquisition was allocated to ments at its coal-fired stations inVirginia and West Virginia. The the assets and liabilities acquired based on their estimated fair Company continues to commit to additional measures inits current values as of the date of acquisition. Inconnection with the termi-financial plans and capital budget to satisfy the requirements of nation of the agreement, the Company expects to record an after-the Consent Decree. tax charge of approximately $46 million.

20041 Pag 24

Long-Term Power Tolling Contract Costs of environmental compliance, liabilities and liti-In the fourth quarter of 2004, the Cofnpany recorded a $112 million gation could exceed the Company's estimates which could after-tax charge related to its interest in a Ion-iterm power tolling adversely affect iti results of operations. Compliance with contract with a 551 megawatt combined cycle facility located in federal. state and local environmental laws and regulations may Batesville, Mississippi. The Company decided to divest its interest result in increased capital, operating and other costs, including in the long-term power tolling contract in connection with Domin- remediation and containment expenses and monitoring obliga-ion's reconsideration of the scope of certain activities of the Clear- tions. Inaddition, the Company may be a responsible party for inghouse, including those conducted on behalf of the Company's environmental clean-up at a site identified by a regulatory body.

business segments, and Dominion's ongoing strategy to focus on Management cannot predict with certainty the amount and timing business activities within the MAIN to Maine region. The charge is of all future expenditures related to environmental matters based on the Company's evaluation of preliminary bids received because of the difficulty of estimating clean-up and compliance from third parties, reflecting the expected amount of consideration costs, and the possibility that changes will be made to the current that would be required by a third party for its assumption of the environmental laws and regulations. There isalso uncertainty in Company's interest in the contract inthe first quarter of 2005. quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.

The Company is exposed to cost-recovery shortfalls Risk Factors and Cautionary Statements That May Affect because of capped base rates and amendments to the fuel Future Results factor statute in effect in Virginia. Under the Virginia Factors that may cause actual results to differ materially from Restructuring Act, as amended in April 2004, the Company's base those indicated inany forward-looking statement include weather rates (excluding, generally, a fuel factor with limited adjustment conditions; governmental regulations; cost of environmental com-provisions, and certain other allowable adjustments) remain pliance; inherent risk in the operation of nuclear facilities; fluctua-unchanged until December 31, 2010 unless modified or terminated tions inenergy-related commodities prices and the effect these consistent with the Virginia Restructuring Act. Although the could have on the Company's earnings, liquidity position and the Virginia Restructuring Act allows for the recovery of certain underlying value of its assets; trading counterparty credit risk; generation-related costs during the capped rates period, the capital market conditions, including price risk due to marketable securities held as investments intrusts and benefit plans; fluctua- Company remains exposed to numerous risks of cost-recovery tions in interest rates; changes inrating agency requirements or shortfalls. These include exposure to potentially stranded costs, ratings; changes in accounting standards; collective bargaining future environmental compliance requirements, tax law changes, agreements and labor negotiations; the risks of operating busi- costs related to hurricanes or other weather events, inflation, the nesses in regulated industries that are subject to changing regu- cost of obtaining replacement power during unplanned plant latory stnictures; changes to regulated electric rates recovered by outages and increased capital costs. Inaddition, under the 2004 the Company; the transfer of control over electric transmission amendments to the Virginia fuel factor statute, the Company's facilities to a regional transmission organization; and political and currentVirginia fuel factor provisions are locked-in until the earlier economic conditions (including inflation and deflation). Other more' of July 1,2007 or the termination of capped rates by order of the specific risk factors are as follows: Virginia Commission.

The Company's operations are weather sensitive. The The amendments provide for a one-time adjustment of the Companys results of operations can be affected by changes inthe Company's fuel factor, effective July 1,2007 through December weather. Weather conditidns directly influence the demand for 31, 2010. with no adjustment for previously incurred over-recovery electricity and affect the price of energy commodities. In addition, or under-recovery, thus'eliminating deferred fuel accounting. As a severe weather, including hurricanes. Wrnter storms and droughts, result of the locked-in fuel factor and the uncertainty of what the can be destructive, causing outages and property damage that one-time adjustment will be, the Company is exposed to fuel price require the Company to incur additional expenses. risk. This risk includes exposure to increased costs of fuel, The Companmy is tubjuct to campiex gover.ment regu- including the energy portiori of certain purchased power costs.

lation that could adversely affect its operations. The Compa- Under the Virginia Restructuring Act, the generation ny's operations are subject to extensive federal, state and local portion of the Company's electric utility operations is open regulation and may require numerous permits, approvals and to competition and resulting uncertainty. Under the Virginia certificates from various governmental agencies. The Company Restructuring Act, the generation portion of the Company's electric must also comp!y with environmental legislation and associated utility operations in Virginia isopen to competition and is no longer regulations. Management believes the necessary approvals have subject to cost-based regulation. To date, the competitive market been obtained for the Company's existing operations and that its has been slow to develop. Consequently, it isdifficult to predict business is conducted inaccordance with applicable laws. How- the pace at which the competitive environment will evolve and the ever, new laws or regulations, or the revision or reinterpretation of extent to which the Company will face increased competition and existing laws or regulations, may require the Company to incur be able to operate profitably within this competitive environment.

additional expenses.

2004/Page 25

There areinherent risksinthe operation of nuclearfacili- trol may increase its cost of borrowing or restrict its ability to ties. The Company operates nuclear facilities that are subject to access one or more financial markets. Such disruptions could inherent risks. These include the threat of terrorist attack and ability include an economic downturn, the bankruptcy of an unrelated to dispose of spent nuclear fuel, the disposal of which issubject to energy company or changes to the Company's credit ratings.

complex federal and state regulatory constraints. These risks also Restrictions on the Company's ability to access financial markets include the cost of and the Company's ability to maintain adequate may affect its ability to execute its business plan as scheduled.

reserves for decommissioning, costs of plant maintenance and Changing rating agency requirements could negatively exposure to potential liabilities arising out of the operation of these affect the Company's growth and business strategy. As of facilities. The Company maintains decommissioning trusts and February 1,2005, the Companys senior secured debt israted external insurance coverage to manage the financial exposure to. A-, negative outlook, by Standard & Poor's and A2, stable outlook, these risks. However, it ispossible that costs arising from claims by Moodys. Both agencies have implemented more stringent could exceed the amount of any insurance coverage. applications of the flnarncial requirements for various ratings lev-The use of derivative instruments could result in finan- els. Inorder to'maihtain its current credit ratings inlight of these cial losses and liquidity constraints. The Company uses or future new requirements, the Company may find it necessary to derivative instruments, including futures, forwards, options and take steps or change its business plans inways that may adversely swaps, to manage its commodity and financial market risks. In affect its growth and earnings. A reduction inthe Company's credit addition, the Company purchases and sells commodity- based ratings by either Standard & Poor's or Moody's could increase its contracts inthe natural gas, electricity and oil markets for trading borrowing costs. adversely affect operating results, and could purposes. In the future, the Company could recognize financial require it to post additional margin inconnection with some of its losses on these contracts as a result of volatility in the market trading and marketing activities.

values of the underlying commodities or if a counterparty fails to Potential changes in accounting practices may perform under a contract Inthe absence of actively quoted market adversely affect the Company's financial results. The prices and pricing information from external sources, the valuation Company cannot predict the impact that future changes in of these contracts involves management's judgment or use of accounting standards cr practices may have on public companies estimates. As a result, changes inthe underlying assumptions or' ingeneral, the energy industry or its operations specifically. New use of alternative valuation methods could affect the reported fair- accounting standards could be issued that could change the way value of these contracts. the Company records revenues, expenses, assets and liabilities.

For additional information concerning derivatives and These changes inaccounting standards could adversely affect the commodity-based trading contracts, see Market Rate Sensitive Company's reported earnings or cculd increase reported liabilities.

Instruments and Risk Management inItem 7A. Quantitative and Failure to retain and attract key executive officers and Qualitative Disclosures About Market Risk and Notes 2 and 7 to other skilled professional and technical employees could have the Consolidated Financial Statements. an adverse effect ou the operations of the Comnpany.

The Company is exposed to market risks beyond its Implementation of the Company's growth strategy isdependent on its control in its energy clearinghouse operations which could ability to recruit, retain and motivate employees. Competition for adversely affect its results of operations and future growth. skilled employees insome areas is high and the inability to retain and The Company's energy clearinghouse and risk management oper- attract these employees could adversely affect the Company's busi-ations are subject to multiple market risks including market liquid- ness and future financial condition.

ity, counterparty credit strength and price volatility. Many industry participants have experienced severe busines's downturns resulting Item 7A.,Quantitative and Qualitative in some companies exiting or curtailing their participation inthe Disclosures About Market Risk energy trading markets. This has led to a reduction inthe number of trading partners and lower industry trading revenues. Declining The matters discussed in this Item may contain forward-looking creditworthiness of some of the Company's trading counterpartics statements' as described in'the introductory paragraphs under Part 11,Item 7. MD&A of this Form 10-K The readers attention is may limit the level of its trading activities with those parties and increase the risk that these parties may not perform under a con-. directed to those paragraphs and Risk Factors and Cautionary tract Statements ThatMayA ffctFuture Results inMD&A, for dis-An inability to access financial markets could affect the cussion of various risks and uncertainties that may affect the execution of the Company's business plan. The Company future of the Company.

relies on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital Market Rate Sensitive Instruments and Risk Management requirements not satisfied by the cash flows from its operations. The Company's financial instruments, commodity contracts and Management believes that the Company will maintain sufficient related derivative instruments are exposed to potential losses due access to these financial markets based upon current credit rat- to adverse changes ininterest rates, foreign currency exchange ings. However, certain disruptions outside of the Company's con-2004/ Page 26

rates, commodity prices and equity security prices, as described Interest Rate Risk below. Interest rate risk generally isrelated to the Company's The Company manages its interest rate risk exposure predom-outstanding debt. Commodity price risk is present inthe Compa- inantly by maintaining a balance of fixed and variable rate debt.

ny's electric operations and energy marketing and trading oper- The Company also enters into interest rate sensitive derivatives, ations due to the exposure to market shifts for prices received and including interest rate swaps and interest rate lock agreements.

paid for natural gas, electricity and other commodities. The For financial instruments outstanding at December 31, 2004, a Company uses derivative instruments to manage price risk hypothetical 10% increase in market interest rates would decrease exposures for these operations. The Company is exposed to equity annual earnings by approximately $3million. A hypothetical 10%

price risk through various portfolios of equity securities. increase inmarket interest rates, as determined at December 31, 2003, would have resulted ina decrease in annual earnings of The following sensitivity analysis estimates the potential loss approximately $2million.

of future earnings or fair value from market risk sensitive instru-ments over a selected time period due to a 10% unfavorable Foreign Currency Exchange Risk change incommodity prices, interest rates and foreign currency The Company manages its foreign exchange risk exposure asso-exchange rates. ciated with anticipated future purchases of nuclear fuel processing services denominated inforeign currencies by utilizing currency Commodity Price Risk forward contracts. As a result of holding these contracts as Trading Activities hedges, the Company's exposure to foreign currency risk for these As part of its strategy to market energy and to manage related purchases is minimal. A hypothetical 10% unfavorable change in risks, the Company manages a portfolio of commodity-based relevant foreign exchange rates would have resulted in a decrease derivative instruments he'd for trading purposes. These contracts of approximately $10 million and $15 million inthe fair value of are sensitive to changes inthe prices of natural gas, electricity and currency forward contracts held by the Company at December 31, certain other commodities. The Company uses established policies 2004 and 2003, respectively.

and procedures to manage the risks associated with these price Investment Price Risk fluctuations and uses derivative instruments, such as futures, The Company is subject to investment price risk due to marketable forwards, swaps and options, to mitigate risk by creating offsetting securities held as investments in nuclear decommissioning trust market positions. A hypothetical 10% unfavorable change in funds. Inaccordance with current accounting standards, these commodity prices would have resulted In a decrease of approx- marketable securities are reported on the Consolidated Balance imately $104 million and $100 million inthe fair value of its Sheets at fair value. The Company recognized net realized gains commodity-based financial derivatives held for trading purposes as (net of investment income) on nuclear decommissioning trust of December 31, 2004 and 2003, respectively. investments of $24 million for 2004 and $36 million for 2003. The The impact of a change in energy commodity prices cn the Company recorded, inAOCI, net unrealized gains on Company's trading derivative commodity instruments at a point in decommissioning trust investments of $49 million for 2004 and net time is not necessarily representative of the results that will be unrealized gains of $100 million for 2003.

realized when such contracts are ultimatelysettled. Dominion sponsors empioyee pension and other postretirement benefit plans, inwhich the Companys employees participate, that Non-Trading Activities hold investments intrusts to fund benefit payments. To the extent The Company manages the price risk associated with purchases and that tha values of investments he'd inthese trusts decline, the sales of natural gas and electricity by using derivative commodity effect will be reflected inthe Company's recognition of the peri-instruments including futures, forwaids, options and swaps. For odic cost of such employee benefit plans and the determination of sensitivity analysis purposes, the fair value of the Company's non-. the amount of cash to be contributed by the Company to the trading derivative commodity iristrurmerits isdeteimined based on employee benefit plans.

models that consider tie rnarket [rices o. cornmodities infuture periods, the volatility of the market prices in each period, as wall as Risk Management Policies the time value factors of the derivative instruments. Market prices.. The Company has operating procedures in place that are and volatility are principally determined based or; quoted prices on administered by experienced management to help ensure that the futures exchange. A hypothetical 10% unfavorable change in proper internal controls are maintained. Inaddition, Dominion has market prices of the Company's non-trading ccmmodity-based established an independent function at the corporate level to mon-financial derivative instruments would have resulted ina decrease in itor compliance with the risk management policies of all sub-fair value of approxiniately $12 million and $6million as of . sidiaries, including the Compan/. Dominion maintains credit policies that include the evaluation of a prospective counterparty's financial December 31, 2004 and 2003, respectively.

condition, collateral requirements where deemed necessary and the The impact of a change inenergy commodity prices on the use of standardized agreements that facilitate the netting of cash Company's non-trading commodity based financial derivative flows associated with a single counterparty. Inaddition, Dominion instruments at a point intime is not necessarily representative of the also monitors the financial condition of existing counterparties on an results that will be realized when such contracts are ultimately set-ongoing basis. Based on Dominion's credit policies and the Compa-tled. Net losses from derivative commodity instruments used for ny's December 31, 2004 provision for credit losses, management hedging purposes, to the extent realized, are substantially offset by believes that it is unlikely that a material adverse effect on the recognition of the hedged transaction, such as revenue from sales. 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 20041 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 inthe 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 inthe United States of America. Other financial information inthe Form 10-K is consistent with that inthe 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 inaccordance with established procedures. Management recognizes the inherent limitations of any system of internal control and, therefore, cannot pro-vide absolute assurance that the objectives of the established internal controls will be met. This system includes written policies, an organ-izational 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 iscomprised entirely of independent directors. Deloitte & Touche LLP's audit was conducted inaccordance 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 ischaracterized and reflected inthe Companys 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 (awholly-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 inthe 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 inaccordance 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 inthe 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, inall 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 inthe period ended December 31, 2004, inconformity with accounting principles generally accepted inthe United States of America.

As discussed inNote 3 to the consolidated financial statements, in2003 the Company changed its methods of accounting to adopt new accounting standards for: asset retirement obligations, contracts involved inenergy trading, derivative contracts not held for trading pur-poses, 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 1 Page 30

Virginia Electric and Power Company Consolidated Statements of Income Year Ended December 31, 2004 2003 2002 Imillions)

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-frandatorily 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.

20041 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 in2004 and $9in2003) 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 1-.910 11,738 Deferred Charges and Other Assets Regulatory assets 361 438 Derivative assets 174 227 OLher 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 December31, 2004 2003 (millions)

UABIUTIES AND SHAREHOLDERS EQUITY Current Uabilities 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 Uabilities Deferred income taxes Z200 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 in2004 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 Accumulated Common Stock Other Other Paid-In Retained Comprehensive Shares Amount Capital Earnings Income (Loss) Total (shares inthousands, all other amounts inmillions)

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 $4tax expense 7 7 Amount reclassified to net income:

Net losses on derivatives-hedging activities, net of $2tax 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 $9tax 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 $5tax expense (7) (7 Net losses on derivatives-hedging activities, net of $1tax 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 December31, 2003 178 2,888 38 1,405 82 4413 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 $1tax 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 SW Equity contribution by parent 11 11 Tax benefit from stock awards and stock options exercised 1 1 Dividends (534) (534)

Balance at December31,2004 198 $3388 $50 $1,302 $129 $4,869 The accompanying notes are an integral part of the Consolidated Financial Statements.

2004 1 Page 34

Virginia Electric and Power Company Consolidated Statements of Cash Flows Year Ended December31, 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)

Irncrease (decrease) incash 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 inamounts payable to parent - - 150 Conversion of amounts payable tu parent tu other psid-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 billed to its utility customers. The Company estimates unbilled Virginia Electric and Power Company (the Company), a Virginia utility revenue based on historical usage, applicable customer public service company, is a wholly-owned subsidiary of Dominion rates, weather factors and total daily electric generation supplied, Resources, Inc. (Dominion). The Company is a regulated public after adjusting for estimated losses of energy during transmission.

utility that generates, transmits and distributes electric energy The primary types of sales and service activities reported as within an area of approximately 30,000 square-miles inVirginia operating revenue include:

and northeastern North Carolina. It sells electricity to approx-

• Regulated electric sales consist primarily of state-regulated imately 2.3 million retail customer accounts, including gov- retail electric sales, federally-regulated wholesale electric ernmental agencies, and wholesale customers such as rural sales and electric transmission services subject to cost-of-electric cooperatives, municipalities, power marketers and other service rate regulation; utilities. The Virginia service area comprises about 65% of Virgin-

• Nonregulated electric sales consist primarily of excess ia's total land area but accounts for over 80% of its population. generation sold at market-based rates and electric trading The Company has trading relationships beyond the geographic revenue; limits of its retail service territory and buys and sells natural gas,

• Nonregulatedgas sales consist primarily of sales of natural gas electricity and other energy-related commodities. Within this at market-based rates, brokered gas sales and gas trading document, the Company' refers to the entirety of Virginia Electric revenue; and and Power Company, including its Virginia and North Carolina

• Otherrevenue consists primarily of sales of coal and also operations and its consolidated subsidiaries. includes miscellaneous service revenue from electric The Company manages its daily operations through three distribution operations, sales of oil and other miscellaneous operating segments: Generation, Energy and Delivery. In addition, revenue.

the Company reports its corporate and other functions as a seg- See Derivative Instruments below for a discussion of ment. accounting changes, effective January 1,2003 and October 1, 2003, which impacted the recognition and classification of changes infair value, including settlements, of contracts held for Note 2. Significant Accounting Policies energy trading and other purposes.

General Electric Fuel and Purchased Energy-Deferred Costs The Company makes certain estimates and assumptions in Where permitted by regulatory authorities, the differences preparing its Consolidated Financial Statements in accordance between actual electric fuel and purchased energy expenses and with accounting principles generally accepted inthe United States the levels of recovery for these expenses incurrent rates are of America. These estimates and assumptions affect the reported deferred and matched against recoveries in future periods. The amounts of assets and liabilities, the disclosure of contingent deferral of costs or recovery of fuel rate revenue inexcess of assets and liabilities at the date of the financial statements and current period expenses is recognized as a regulatory asset or the reported amounts of revenue and expenses for the periods liability.

presented. Actual results may differ from those estimates. Effective January 1,2004, the Company's fuel factor provi-The Consolidated Financial Statements included, after sicns for its Virginia retail customers are locked in until the earlier eliminating intercompany transactions and balances, the accounts of July 1,2007 or the termination of capped rates, with a oce-tima of the Company and its majority-owned subsidiaries, and those adjustment of the fuel factor, effective July 1,2007 through variable interest entities (VIEs) where the Company has been December 31, 2010, with no adjustment for previously incurred determined to be the primary beneficiary. over-recover/ or under-recovery, thus eliminating deferred fuel Certain amounts inthe 2003 and 2002 Consolidated Financial accounting for the Virginia jurisdiction. As a result, approximately Statements and footnotes have been reclassified to conform to the 12% of the cost of fuel used inelectric generation and energy 2004 presentation. purchases used to serve utility customers issubject to deferral accounting. Prior to the amendments to the Virginia Electric Utility Operating Revenue Restructuring Act (Virginia Restructuring Act) and the Virginia fuel Operating revenue is recorded on the basis of services rendered, factor statute in2004, approximately 93% of the cost of fuel used commodities delivered or contracts settled and includes amounts inelectric generation and energy purchases used to serve utility yet to be billed to customers. The Company's customer accounts customers had been subject to deferral accounting. Deferred costs receivable at December 31, 2004 and 2003 included $251 million associated with the Virginia jurisdictional portion of expenditures and $234 million, respectively, of accrued unbilled revenue based incurred through 2003 continue to be reported as regulatory on estimated amounts of electric energy delivered but not yet assets, pending recovery through future rates.

2004I/Page 36

Notes to Consolidated Financial Statements, Continued Income Taxes Valuation Mothods The Company files a consolidated federal income tax return and Fair value isbased on actively quoted market prices, if available. In participates inan intercompany tax allocation agreement with the absence of actively quoted market prices, the Company seeks Dominion and its subsidiaries. The Company's current income indicative price information from external sources, including broker taxes are based on its taxable income, determined on a separate quotes and industry publications. If pricing information from company basis. At December 31, 2004 and 2003, the Companys external sources is not available, the Company must estimate Consolidated Balance Sheets include $24 million of current taxes prices based on available historical and near-term future price payable to Dominion (recorded inaccrued interest, payroll and information and certain statistical methods, including regression taxes) and $4million of current taxes receivable from Dominion analysis.

(recorded inprepayments), respectively. However, under the Public For options and contracts with option-like characteristics where Utility Holding Company Act of 1935 (1935 Act) and the inter- pricing information is not available from external sources, the company tax allocation agreement, the Companys cash payments Company generally uses a modified Black-Scholes Model that to Dominion are limited. Where permitted by regulatory author- considers time value, the volatility of the underlying commodities ities, the treatment of temporary differences can differ from the and other relevant assumptions when estimating fair value. Other requirements of Statement of Financial Accounting Standards option models are used by the Company under special circum-(SFAS) No. 109, Accounting forIncome Taxes. Accordingly, a stances, including a Spread Approximation Model, when contracts regulatory asset has been recognized if it is probable that future include different commodities or commodity locations and a Swing revenue will be provided for the payment of deferred tax liabilities. Option Model, when contracts allow either the buyer or seller the The Company establishes a valuation allowance when it is more ability to exercise within a range of quantities. For contracts with likely than not that all or a portion of a deferred tax asset will not unique characteristics, the Company estimates fair value using a be realized. Deferred investment tax credits are being amortized discounted cash flow approach deemed appropriate inthe circum-over the service lives of the properties giving rise to such credits. stances.and applied consistently from period to period. If pricing information is not available from external sources, judgment is Cash and Cash Equivalents required to develop the estimates of fair value. For individual Current banking arrangements generally do not require checks to contracts, the use of different valuation models or assumptions be funded until actually presented for payment. At December 31, could have a material effect on the contract's estimated fair value.

2004 and 2003, the Company's accounts payable includes

$41 million and $54 million, respectively of checks outstanding but Derivative instruments Designated as Hodging Instruments not yet presented for payment For purposes of the Consolidated The Company designates derivative instruments, held for purposes Statements of Cash Flows, the Companyconsiders c'ash and cash other than trading, as fair value or cash flow hedges for accounting equivalents to include cash on hand, cash inbanks and temporary purposes. For all derivatives designated as hedges, the relation-investments purchased with a'remaining maturity of three months ship between the hedging instrument and the hedged item is or less. formally documented, as well as the risk management objective and strategy for using the hedging instrument The Company Derivative Instruments - assesses whether the hedge relationship between the derivative The Company uses.derivative instruments such as futuzes,.swaps, and the hedged item ishighly effective in offsetting changes infair forwards and options to manage the commodity, currency value or cash flows both at the inception of the hedge and on an exchange and financial market risks of its business operations. The ongoing basis. Any change infair value of the derivative that is not Company also manages a portfolic of commodity contracts held for effective inoffsetting changes inthe fair value or cash flows of the trading purposes as part of its strategy to market energy end to hedged item is recognized currently inearnings. Also, management manage related risks. may elect to exclude certain gains or losses on hedging instru-All derivatives, except those for which an exception applies, ments from the measurement of hedge effectiveness, such as are reported on the Consolidated Balance Sheets at fair value. One gains or losses attributable to changes inthe time value of options of the exceptions - norn'al purchases and normal sales - may be or changes inthe difference between spot prices and forward elected when the contract satisfies certain criteria, including a prices, thus requiring that such changes be recorded currently in requirement that physical delivery of the underlying commodity is earnings. The Company discontinues hedge accounting pro-probable. Expenses and revenue resulting from deliveries under spectively if a derivative ceases to be highly effective as a hedge.

normal purchase contracts and normal sales contracts, Cash Flow Hedges-A portion of the Company's hedge strat-respectively, are included in earnings at the time of contract per. egies represents cash flow hedges of the variable price risk asso-formance. Derivative contracts that are subject to fair value ciated with the purchase and sale of natural gas. The Company accounting, including unrealized gain positions and purchased also uses foreign currency forward contracts to hedge the varia-options, are reported as derivative assets. Derivative contracts bility inforeign exchange rates and interest rate swaps to hedge representing unrealized losses and options sold are reported as its exposure to variable interest rates on long-term debt. For cash derivative liabilities. For derivatives that are not designated as hedging instruments, any changes infair value are recorded in earnings.

2004/ Page 37

Notes to Consolidated Financial Statements.

Continued flow hedge transactions inwhich the Company is hedging the

• Fnancially-Settled Derivatives-Not Held for Trading variability of cash flows, changes inthe fair value Purposes of the derivative or Designated as Hedging Instnuments:AII unrealized changes are reported in accumulated other comprehensive income (loss) infair value and settlements are presented in other operations (AOCI), to the extent effective in offsetting changes in the hedging and maintenance expense on a net basis.

relationship, until earnings are affected by the hedged item. For

• Physically-Settled Derivatives-Not Held for Trading cash flow hedge transactions that involve a forecasted Purposes transaction, orDesignated as Hedging Instruments: Effective October the Company would discontinue hedge accounting 1,.

if the occur- 2003, all statement of income related amounts for physically rence of the forecasted transaction was determined to be no settled derivative sales contracts are presented inrevenue, longer probable. The Company would reclassify any derivative while all statement of income related amounts for physically gains or losses reported inAOCI to earnings when the forecasted settled derivative purchase contracts are reported in expenses.

item isincluded inearnings, if it should occur, or earlier, if it For periods prior to October 1,2003, unrealized changes becomes probable that the forecasted transaction in fair would not occur. value for physically settled derivative contracts were presented Fair Value Hedges-The Company also engages infair value inother operations and maintenance expense on a net hedges by using derivative instruments to mitigate basis.

the fixed price exposure inherent incertain natural gas inventory. In Effective January 1.2003, the Company recognizes revenue addition, the or Company has designated interest rate swaps as fair expense from all non-derivative energy-related contracts value hedges on a to manag3 its interest rate expcsure on certain fixed-rate gross basis at the time of contract performance, settlement long- or term debt. For fair value hedge transactions, changes termination. Prior to 2003, all energy trading contracts, including inthe fair value of the derivative will generally be offset currently non-derivative contracts, were recorded at fair value with inearnings changes by the recognition of changes inthe hedged item's in fairvalue reported in revenue on anet basis.

fair value.

Statement of Income Presentation-Gains and losses on Nuclear Decommissioning Trust Funds derivatives designated as hedges, when recognized, are included The Company analyzes all securities classified as available-for-in operating revenue, operating expenses or interest and related sale to determine whether adecline in its fair value should charges in the Consolidated Statements of Income. be Specific line considered other-than-temporary. The Company uses item classification is determined based on the nature several cri-of the risk teria to evaluate other-than-temporary declines, including underlying individual hedge strategies. The portion length of of gains or time over which the market value has been lower than its losses on hedging instruments determined to be cost, the ineffective and percentage of the decline as compared to its average the portion of gains or losses on hedging instruments cost and the excluded expected fair value of the security. If the market value of from the measurement of the hedging relationship's such as gains or losses attributable to changes inthe effectiveness, rity has been less than cost for greater than nine months the secu-time value of and the options or changes inthe difference between spot decline invalue isgreater than 50% of its average cost, prices and the secu-forward prices, are included in other operations and rity iswritten down to its expected recovery value. If maintenance only one of expense. the above criteria ismet, afurther analysis isperformed uate the expected recovery value baszd on third party to eval-price DerivativeInstruments Held fhr Trading and Other Purposes gets. Ifthe third party price quotes are below the securiti's tar-As part of its strategy to market energy and to manage average cost and one of the other criteria has been met,  :

related thes risks, the Company manages a portfolio cf cummodity-based decline isconsidered other-than-temporary, and the security derivative instruments held for trading purposes, primarily is natural written down to its expected recovery value.

gas and electricity The Company uses established policies and Property, Plant and Equipment procedures to manage the risks associated with the price fluctua- Property, plant and equipment, including additions and tions inthese energy conmodities and uses various replace-,

derivative ments, isrecorded at original cost, including labor, materials, instruments to reduce risk by creating offsetting market asset positions. retirement costs, other direct costs and capitalized interest.

The Company may also hold certain derivative The, instruments that cost of repairs and maintenance, including minor additions are not held for trading purposes and are not designated and as hedges replacements, ischarged to expense as incurred. In2004, for accounting purposes. However, to the extent the 2003 Company does and 2002, the Company capitalized interest costs of $7 not hold offsetting positions for such derivatives, million, $18 management million and $17 million. respectively.

believes these instruments would represent economic hedges that For electric distribution and transmission property subject mitigate exposure to fluctuations incommodity prices, rates and foreign exchange rates.

interest cost-of-service utility rate regulation, the depreciable cost to of such property, less salvage value, ischarged to accumulated Statement of Income Presentation: deprecia-tion at retirement. Cost of removal collections from utility Derivatives Held for Trading Purposes:AII changes in customers and expenditures not representing assets fair value, retirement including amounts realized upon settlement, are presented obligations (AR~s) are recorded as regulatory liabilities in or regu-revenue on a net basis as nonregulated electric sales, latory assets.

non-regulated gas sales and other revenue. For generation-related property, cost of removal not associated with AROs ischarged to expense as incurred. The Company 2004 /Page 38

Notes to Consolidated Financial Statements, Continued records gains and losses upon retirement of generation-related realized gains and losses inother income (loss) and records unreal-property based upon the difference between proceeds received, if ized gains and losses inAOCI.

any, and the property's undepreciated basis at the retirement date.

Nuclear Decommissioning-20J2 Depreciation of property, plant and equipment is computed on In accordance with the accounting policy recognized by regulatory the straight-line method based on projected service lives. The authorities having jurisdiction over its electric utility operations, Company's depreciation rates on property, plant and equipment for the Company recognized an expense for the future cost of decom-2004,2003 and 2002 are as follows:

missioning inamounts equal to the sum of amounts collected from 2004 2003 2002 ratepayers and earnings on trust investments dedicated to funding (percent) the decommissioning of its nuclear plants. The trust investments Generation 1.97 1.83 1.88 were reported at fair value with the accumulated provision for Transmission 1.97 1.96 2.14 decommissioning 'reported as a liability. Net realized and unreal-Distribution 3.46 3.43 3.55 General and other 5.76 5.47 5.24 ized earnings on the trust investments, as well as an offsetting expense to increase the accumulated provision for decommission-ing, were recorded as a component of other income (loss).

Amortization of nuclear fuel used inelectric generation is pro-vided on a unit-of-production basis sufficient to fuliy amortize, over Amortization of Debt Issuance Costs the estimated service life, the cost of the fuel plus permanent The Company defers and amortizes debt issuance costs and debt storage and disposal costs. premiums or discounts over the expected lives of the respective In 2002, the Company extended the estimated useful lives of debt issues, considering maturity dates and, if applicable, most of its fossil fuel power stations and electric transmission and redemption rights held byothers. As permitted by regulatory' -

distribution property based on depreciation studies "hat indicated authorities, gains or losses resulting from the refinancing of debt longer lives were appropriate. The changes reduced annual allocable to utility operations subject to cost-based rate regulation depreciation expense for those assets by approximately $64 mil- have also been deferred and amortized over the lives of the new lion. issues.

Impairment of Long-Lived and Intangible Assets The Company performs an evaluation for impairment whenever events or changes incircumstances indicate that the carrying Note 3. Newly Adopted Accounting Standards amount of long-lived assets or intangible assets with finite lives 2004 may riot be recoverable. These assets are written down to fair FRN 46 -

value if the sum of the expected future undiscounted cash flows is The Company adopted FASB Interpretation No. 46 (revised less than thedca'rrying amounts. December 2003), Consolidation of Variable Interest Entities, (FIN 46R) for its interests inVIEs that are not considered special pur-Regulatory Assets and Liabilities pose entities on March 31, 2004. As discussed below, the Com-For utility operations subject to federal or state cost-of-service rate pany adopted FIN 46R for its interests in special purpose entities regulationiregulatory practices that assign costs to accounting on December 31, 2003. FIN 46R addresses the identification and periods may differ from accounting methods generally applied by consolidation of VIEs, which are entities that are not controllable nonregulated companies. When it is probable that regulators wili through voting interests or inwhich the VIEs' equity investors do allow for the recovery of current costs through future rates not bear the residual economic risks and rewards in proportion to charged to customers, the Company defers these costs as regu- voting rights. There was no impact on the Company's results of latory assets inits financial statements that otherwise would be operations or financial position related to this adoption.

expensed by nonregulated companies. Ukewise, the Company The Company is Eparty to long-term contracts for purchases of recognizes regulatory liabilities in its financial statements when it electric generation capacity and energy from qualifying facilities is probable that regulators will allow for customer credits through and independent power producers. Certain variable pricing terms future rates and when revenue is collected from customers for insome of these contracts cause them to be considered potential expenditures that are not yet incurred. variable interests that require evaluation under the provisions of Asset Retirement Obligations FIN 46R. If a power generator that holds one of these specific Beginning in2003, the Company recognizes its AROs at fair value types of contracts is determined to be aVIE and the Company is as incurred, capitalizing these amounts as costs of the related determined to be the primary beneficiary, the Company would be tangible long- lived assets. Due to the absence of relevant market required to consolidate the entity inits financial statements.

information, fair value is estimated using discounted cash flow Consolidation of one of these potential VlEs would primarily result analyses. The Company reports the accretion of the liabilities due inthe addition of property, plant and equipment, long-term debt to the passage of time as an operating expense. Inaddition, and minority interest to the Company's Consolidated Balance beginning in 2003, the Company classifies all investments held by Sheets. The impact on the Company's Consolidated Statements of its decommissioning trusts as available-for-sale, and recognizes 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 this power purchase agreement in 2004, 2003 and 2002, replaced by the VME's operations, maintenance and interest respectively.

expenses. The VJE's results of operations would be reported as For those six potential VIE supplier entities that have not pro-income attributable to a minority interest, and would not affect the vided sufficient information, the Company will continue its efforts Company's net income. The debt of these potential VIEs, even if to obtain information and will complete an evaluation of its rela-included inthe Company's Consolidated Balance Sheets, would be tionship with each of these potential VIEs, if sufficient information nonrecourse to the Company. is ultimately obtained. The Company has remaining purchase At March 31, 2004, the Company had determined that its power commitments with these six potential VIE supplier entities of $2.6 purchase agreements with ten of these entities would require billion at December 31, 2004. These commitments are incorporated further analysis under FIN 46R. Each of these facilities began inthe Company's disclosure of unconditional purchase obligations commercial operations and service to the Company under the long- included inNote 19. The Company paid $249 million, $250 million term contracts prior to December 31, 2003. Since these entities and $300 million for electric generation capacity and $185 million, were established and are legally owned by parties not affiliated $168 million and $120 million for electric energy to these entities with the Company, the Company submitted requests for in2004. 2003 and 2002, respectively. The Company's exposure to information needed to evaluate the entity and its contractual rela- losses from its involvement with these entities cannot be tionship with the entity under FIN 46R. In addition, the Company determined since losses, if any, would be represented by either: 1) informed the entities that, if the results of its evaluation were to the difference between (a)the amount payable by the Company for indicate that the Company should consolidate the entity, it would energy and capacity under the long-term cortract and (b)amounts also require periodic financial information inorder to perform the recoverable through sales to retail electric customers inits service accounting required to consolidate the entity inits financial state- territory or wholesale market transactions; or 2)if the potential VIE ments. The objectives of the FIN 46R evaluation are to determine: supplier fails to perform, any amount paid by the Company to (1)whether the Company's interest, represented by the power obtain replacement energy and capacity inexcess of the amounts purchase contract, is a significant variable interest (2)whether the otherwise payable under the long-term contract with the potential supplier entity is a VIE; and (3)if the supplier entity isa VIE, VIE supplier entity.

whether the Company isthe primary beneficiary. The Emerging Issues Task Force (EITF) has added a project to its In response to these requests, five of the potential VIE supplier agenda to consider what variability should be considered when entities provided some, but limited, information. After completing determining whether an interest isa variable interest It is its analysis of this information, the Company concluded that one of uncertain how this EITF project or other future efforts to further the supplier entities is a VIE, its power purchase contract repre- interpret FIN 46R could impact the Company's conclusions based sented a significant variable interest inthe VIE, but the Company is on its use of information received.

not its primary beneficiary. Inaddition, using the limited information received, the Company concluded that it does not hold 2003x significant variable interests intwo of the potential VIE supplier SFAS No. 143 entities. Effective January 1,2003, the Company adopted SFAS No. 143, Since the enactment of the Virginia Restructuring Act, the which provides accounting requirements for the recognition and Company has sought to renegotiate or terminate long-term power measurement of liabilities associated with the retirement of purchase contracts inits efforts to reduce the cost structure of its tangible long-lived assets. The affect of adopting SFAS No.. 143 for generation-related operations. In November-2004, the Company 2003, as compared to an estimate of net income reflecting the paid $92 million to terminate its power purchase agreement and to contiruation of former accounting policies, was to increase net acquire the related generating facility from one of the potential VIE income by $160 million. The ircrease was comprised of a $139 suppliers that had not provided information in response to th3 million after-tax gain, representing the cumulative effect of a Company's FIN 46R request. The Company had purchased $20 change inaccounting principle and an increase in income before million, $20 million and $21 million of elsctric generation capacity the cumulative effect of a change in accounting principle of $21 and $4million, $7million and $3million of electric energy under million.

this power purchase agreement in2004, 2003 and 2002, E17FU2-3 respectively. Inaddition, inFebruary 2005, the Company paid $42 On January 1,2003, the Company adopted EITF Issue No. 02-3, million incash and assumed $62 million of debt to terminate its Issues Involved inAccountirig for Derivative Contracts Held for power purchase agreement and to acquire the related generating Trading Purposes and Contracts Involved in Energy Trading and facility from the supplier entity that the Company had determined Risk ManagementActivities, that rescinded EITF Issue No. 98-10, to be a VIE and, inwhich, its power purchase agreement repre- Accounting for Contracts Involved in Energy Trading and Risk sented a significant variable interest. The Company purchased $23 ManagementActivitles. Adopting EITF 02-3 resulted inthe dis-million, $23 million and $24 million of electric generation capacity continuance of fair value accounting for non-derivative contracts and $8million, $10 million and $5million of electric energy under held for trading purposes. Those contracts are recognized as revenue or expense at the time of contract performance, settle-2004 IPage 40

Notes to Consolidated Financial Statements, Continued ment or termination. The EITF 98-10 rescission was effective for As a result, in2004, the Company reported interest expense on the non-derivative energy trading contracts initiated after October 25, junior subordinated notes rather than preferred distribution 2002. For all non-derivative energy trading contracts initiated prior expense on the trust preferred securities.

to October 25, 2002. the Company recognized a loss of $90 million 2002

($55 million after-tax) as the cumulative effect of this change in Pro Fonna Infonnation Reflecting the Adoption of New accounting principle on January 1, 2003.

Standards EITFO3-11 Disclosure requirements associated with the adoption of FIN 46R On October 1, 2003, the Company adopted EITF Issue No. 03-11, and SFAS No. 143 require a disclosure of pro forma net income for Reporting Realized Gains and Losses on Derivative Instruments 2002 as if the Company had applied the provisions of those stan-That Are Subject to FASS Statement No. 133 and Not Held for dards as of January 1, 2002. Had the Company applied those Trading Purposes' as Defined in Issue No. 02-3, on October 1, standards during 2002, net income would have been $778 million.

2003. EITF03-11 addresses classification of income statement Other standards adopted during 2004 and 2003 do not require pro related amounts for derivative contracts. Income statement forma information and are excluded from this amount.

amounts related to periods prior to October 1,2003 are presented as originally reported. See Note 2.

Statement 133Implementation IssU No. 120G Note 4. Recently Issued Accounting Standards Inconnection with a request to reconsider an interpretation of ElIFO3-1 SFAS No. 133, Accounting for Derivative Instruments and Hedging Inaccordance with FSP EITF 03-1-1, the Company delayed its Activities, the FASB issued Statement 133 Implementation Issue adoption of the recognition and measurement provisions of EITF No. C20, Interpretation of the Meaning of 'Not Clearly and Closely 03-1, The Meaning of Other-Than Temporary Impairment and Its Related 'in Paragraph 10(b) regarding Contracts with a Price Application to Certain Investments, which provides guidance for Adjustment Feature. Issue C20 establishes criteria for determining evaluating and recognizing other-than-temporary impairments for whether a contract's pricing terms that contain broad market certain investments in debt and equity securities. This delay will indices (e.g., the consumer price index) could qualify as a normal be in effect until the FASB reaches a final conclusion on issues purchase or sale and, therefore, not be subject to fair value raised in its proposed FSP 03-1-a, which relates primarily to accounting. The Company has several contracts that qualify as' implementation issues concerning certain types of debt securities.

normal purchase and sales contracts under the Issue C20 guid- Pending the adoption of any new guidance that may be final-ance. Howevier, the adoption of Issue C20 required the contracts to ized inthe future, the Company has continued to evaluate its be initially recorded at fair value as of Odtober 1,2003, resulting in available-for-sale securities for other-than-temporary impairment the recognition of an after-tax charge of $101 million,' representing based upon the accounting policy described in Note 2. Inaddition the cumulative effect of the change inaccounting principle. As to issues being addressed by the FASB inFSP 03-1-a, the Company normal purchase and sales, these contracts are not subject to fair and other entities inthe electric industry have sought additional value accounting. guidance from the FASB concerning the proper application of EITF 03-1 to debt and equity securities held innuclear decommissioning RN46R trusts. Given the delayed effective date and the request for addi-On December 31, 2G03, the Company adopted FIN 46FI for its inter-tional guidance described above, the Company cannot predict what ests in special purpose entities, resulting inthe consolidation of a the initial or ongoing impact of applying EITF 03-1 to its nuclear special purpose lessor entity through which the Ccmpany had decommissioning trust investments may have on its results of constructed, financed and leased a power generation project.-As a operations and financial condition at this time.

result, the Consolidated Balance Sheet as of December 31, 2003 reflects an additional $364 milion in net propercv, plant and SFAS No. 151 equipment and deferred charges and $370 million of related debt. InNovember 2004, the FASE issued SFAS No. 151, Inventory This resulted inadditional depreciation expense of approximately Costs-an amendment ofARB No. 43, Chapter 4,which clarifies

$10 million in 2004. The cumulative effect in 2003 of adopting FRN that abnormal amounts of idle facility expense, handling costs, 46R for the Companys interests inthe special purpose entitywas freight, and wasted materials (spoilage) should be recognized as an after-tax charge of $4million, representing depreciation and current period charges, and requires that inmanufacturing oper-amortization expense associated with the consolidated assets. ations, allocation of fixed production overheads to the costs of In 2002, the Company established Virginia Power Capital Trust conversion be based on the normal capacity of the production 11, which sold trust preferred securities to third party investors. The facility. The Company will adopt the provisions of this standard Company received the proceeds from the sa!e of the trust preferred prospectively beginning January 1,2006 and does not expect the securities in exchange for junior subordinated notes issued by the adoption to have a material impact on its results of operations and Company to be held by the trust. Upon adoption of FIN 46R, the financial condition.

Company began reporting as long-term debt its junior subordinated notes held by the trust rather than the trust preferred securities.

2004/Page 41

Notes to Consolidated Financial Statements, Continued SFAS No. 153 The statutory U.S. federal income rate reconciles to the effec-In December 2004, the FASB issued SFAS No. 153, Exchanges of tive income tax rates as follows:

Nonmonetary/Assets-an amendment of APB Opinion No. 29, Year Ended December 31, which requires that all commercially substantive exchange trans-actions, for which the fair value of the assets exchanged are reli- 2004 2003 2002 ably determinable, be recorded at fair value, whether or not they U.S statutory rate 35.0% 35.0% 35.0%

Increases (reductionsl resulting from:

are exchanges of similar productive assets. This amends the Utility plant differences 0.2 10.6i (0.21 exception from fair value measurements inAPB No 29, Accounting Amortization of investment tax credits (1.8) (.3) 1.11 for Nonmonetary Transactions, for nonmonetary exchanges of State income tax, net of federal tax benefit 3.6 3.2 3.0 Employee stock ownership plan deduction 10.7) similar productive assets and replaces it with an exception for only Other, net (0.6) 0.3 (1.2) those exchanges that do not have commercial substance. The Effective tax rate 35.7% 35.5%

36.6%

Company will adopt the provisions of this standard prospectively beginning July 1,2005 and does not expect the adoption to have a Deferred income taxes reflect the net tax effects of temporary material impact on its results of operations and financial condition.

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 Note 5. Operating Revenue the following:

The Company's operating revenue consists of the following:

December 31, Year Ended December 31. 2004 2003 2004 2003 2002 (millions)

(millions) Deferred income tax assets Regulated electric sales $5,180 $4,876 S4,157 Deferred investment tax credits $ 25 $ 31 Nonregulated electric sales (141) 44 i7 Other 112 54 Nonregulated gas sales 42 263 (58) Total deferred income tax assets 137 85 Other 660 254 95 Deferred income tax liabilities:

Total operating revenue $5,741 $5,437 $4,972 Depredation method and plant basis differences' 1,912 1,766 Income taxes recoverable through future rates 20 15 Deferred state income tax - 123 131 Note 6. Income Taxes Other ' 170 83 Details of income tax expense were as follows: Total deferred income tax liabilities 2,725 .11995 Total net deferred income tax liabilitiesl) $2,088 $1,910 Year Ended December 31, 21104 . 2003 2002 (1) AtDecember3l,2004and2r03, total net deferred income tax liabilities (millions) indude $112 million and $54 million, respectively, of current deferred tax assets that were reported inother current assets.

Current expense:

Federal $ 79 $87 $297 As a matter of-course, the Company is regularly audited by State 35 4 30 federal and state tax authorities. The Company establishes Total current 114 91 327 liabilities for probable tax-related contingencies and reviews them Deferred expense: in light of changing facts and circumstances. Although the results Federal 140 220 90 State 1 41 25 of these audits are uncertain, the Company believes that the Total deferred 141 261 115 ultimate outcomo will not have a material adverse effect on the.

Amortization of deferred investment Company's financial position. The Company had no significant tax-tax credits, net (16) (161 (17) related contingent liabilities at December 31,2004.

Total income tax expense $239 $336 $425 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 not 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) Note B.Nuclear Decommissioning Trust Funds The Act was signed into law October 22, 2004, and has several The Company holds marketable debt and equity securities innuclear provisions for energy companies including a deduction related to decommissioning trust funds. These investments are classified as taxable income derived from qualified production activities. Under, the Act qualified production activities include the Company's available-for-sale. As described below, prior to adopting SFAS No.

electric generation activities. The Act limits the deduction to the 143, the Company did not record unrealized gains and losses in lesser of taxable income derived from qualified production activ- AOCI, but rather inearnings, offset by a provision for future decom-ities or the consolidated federal taxable income of Dominion and missioning costs. The Company's decommissioning trust funds, as of its subsidiaries. At this time, the Company does not believe the December 31,2004, are summarized below.

qualified production activities deduction will have a material Total Total impact on' the Company's results of operations or financial position Unrealized Unrealized in 2005. Gains Losses Fair included included Value inAOCI inAOCI I" (millions)

Note 7. Hedge Accounting Activities 2034 The Company is exposed to the impact of market fluctuations in Equity securities $ 678 $145 $ 3 the price of natural gas, electricity and other energy-related . Debt securities 392 9 1 Cash and other 49 - -

commodities marketed and purchased as well as currency Total $1,119 $154 $ 4 exchange and'interest rate risks of its business operations. The 2003 Company uses'derivative instruments to mitigate its exposure to Equity securities $ 592 $ 98 $-

these risks'and designates derivative instruments as fair value or Debt securities 382 3 1 cash flow hedges for accounting purposes. Cash and other 36 -

During 2004, in'connection with fair value hedges'of natural Total $1,010 $101 $ 1 gas inventory, the Company recognized innet income-$1 million of (11'In2004, approximately $1million of unrealized losses relate primarily to equity losses as hedge ineffectiveness and $3million of gains attribut- - securities inaloss position for greater than 1 year. There were no securities in able to differences between spot prices and forward prices that an unrealized loss position for greater than 1 year in2003.

are excluded from the measurement of effectiveness under the The fair value of debt securities at December 31, 2004 by hedge strategy. contractual maturity are as follows:

The following table presents selected information'related to cash flow hedges included inAOCI inthe Consolidated Balance Amount Sheet at.December.31, 2004: . - (millions)

Due inone year or less $ 17 Portion Expected Dueafteroneyearthroughfiveyears . 132 Accumulated to be Reclassified Due after five years through ten years 154 Other . to Earnings Due after ten years 89 Comprehensive During the Next Total $392 Income 12 Months Maximum i a After-Tax After-Tax .Term (millions) v ;i . .; - .

• For 2004, proceeds from the sale of available-for-sale securities Cornnod.ties-Gas- $6 $6 7months totaled $237 million; gross realized gains totaled $27 million and Interest Rate 1 - 130 months gross realized losses totaled $24 million. In determining realized Foreign Currency. 31 6 35 months gains and losses, the cost of these securities was determined on a Total $38  ; . $12 specific identification basis.

DecommissioningTrw Investments-2002 The actual amounts that will be reclassified to earnings in2005 Prior to adopting SFAS No. 143, the Company recognized an will vary from the expected amounts presented above as a result expense for the future cost of decommissioning its nuclear plants of changes in market prices, interest rates and foreign exchange equal to the amounts collected from ratepayers and earnings on rates. The effect of amounts being reclassified from AOCI to earn- trust investments dedicated to funding the decommissioning of ings will generally be offset by the recognition of the hedged: those plants. The trusts were reported at fair value with realized transactions (e.g.. anticipated purchases) inearnings, thereby and unrealized earnings on the trust investments, as well as an achieving the realization of prices contemplated by the underlying offsetting expense to increase the accumulated provision for risk management strategies. 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 Annual amortization expense for intangible assets is estimated to be $32 million for 2005, $27 million for 2006, $23 million for Major classes of property, plant and equipment and their 2007, $14 rmillion for 2008 and $11 million for 2009.

respective balances are:

December 31, 21104 2003 Note 11. Regulatory Assets and Liabilities (millions) The Company's regulatory assets and liabilities include the Utility. following:

Generation $10,135 $ 9,780 Transmission 1,635 1,592 December 31, Distribution 6,025 5,796 Nuclear fuel 795 757 2004 2003 Genera and other 608 616 Plant under construction 511 575 (millions) 19,709 19,115 Regulatory assets:

Non-utility-Other 7 13 Income taxes recoverable through future rates(') $ 51 $ 43 Cost of decommissioning DOE uranium Total property, plant and equipment $19,716 $19,129 cnrichment faciHitres{2- 12 /

Deferred fuelN 248 335 Jointly-Owned Utility Plants Rogiona: transmission organization start-up and integration costs" 31 20 The Company's proportionate share of jointly-owned utility plants Other 13 13 at December 31, 2004 follows: Total regulatory assets $361 $438 Bath Regulatory liabilities:

County North Provision for future cost of removalms) $374 $359 Pumped Anna Clover Others 13 15 Storage Power Power Station Station Station Total regulatory liabilities $387 $374 (millions, except percentages)

Ownership interest room% 88.4% 50.0% (11Income taxes recoverable through future rates resulted from the recognition of Plant inservice $ 1,014 S2.067 S 548 additional deferred income taxes not previously recorded under past rate-Accumulated depredation 378 897 112 making practices.

Nuclear fuel - 380 - 12)The cost of decommissioning the Department of Energy's IDOE) uranium Accumulated amortization of nuclear fuel - 285 -

enrichment facilities represents the unamortized portion of the Company's Plant under construction 27 47 3 required contributions to afund for decommissioning and decontaminating the DOE's uranium enrichment facilities The contributions began in1992 and will The co-owners are obligated to pay their share of all future continue over a 15-year period with escalation for inflation. These costs are construction expenditures and operating costs of the jointly owned currently being recovered infuel rates.

(3) Deferred fuel accounting provides that the difference between 11reasonably facilities inthe same proportion as their respective ownership incurred actual cost of fuels used inelectric generation and energy purchases interest. The Company reports its share of operating costs inthe and 2)the recovery for such costs included incurrent rates were deferred and appropriate operating expense (fuel, other operations and main- matched against future revenue. Deferred fuel costs were historically recovered tenance, depreciation and amortization and other taxes, etc.) inthe within two years; however, inconnection with the settlement of the 2003 Virginia fuel rate proceeding, the Company agreed to recover $307 million of Consolidated Statements of Income. previously incurred costs through June 30, 2007 without a return on unrecovered balances.

(4)The Federal Energy Regulatory Commission (FERC) has authorized the deferral Note 10. Intangible Assets of start-up costs incurred by transmission owning companies joining aRegional Transmission Organization (ITO). The Company has deferred $4million instart-All of the Company's intangible assets are subject to amortization. up costs associated with the Alliance Regional Transmission Organization Amortization expense for intangible assets was $27 million, $25 (ARIO) and $24 million associated with the PJM RTO and associated carrying million and $24 million for 2004, 2003 and 2002, respectively. costs of $3million. The Company expects recovery from Virginia jurisdictional There were no material acquisitions of intangible assets in2004 or retail customers to commence at the end of the Virginia retail rate cap period, subject to regulatory approval.

2003. Intangible assets are included inother assets on the Con- (5) Rates charged to customers by the Company's regulated business include a solidated Balance Sheets. The components of intangible assets at provision for the cost of future activities to remove assets expected to be December 31, 2004 and 2003 were as follows: incurred at the time of retirement (6)The Company's other regulatory liability represents the excess of the accumu-204 2003 lated provision for nuclear decommissioning accrued under its prior accounting Gross Gross policy for decommissioning, which was based on amounts being collected from Carrying Accumulated Carrying Accumulated the Companys North Carolina jurisdictional customers to fund future decom-Amount Amortization Amount Amortization missioning activities, over the amounts recognized under SFAS No. 143.

(millions)

Software and software At December 31, 2004, approximately $282 million of the licenses $265 $129 $254 $113 Company's regulatory assets represented past expenditures on Other 50 9 16 7 Total $315 $132 $270 $120 which it does not earn a return. These expenditures consist 2004/ Page 44

Notes to Consolidated Fnancial Statements, Continued primarily of regional transmission organization start-up and Company entered into two joint credit facilities that allow integration costs and a portion of deferred fuel costs. 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 Note 12. Asset Retirement Obligations that terminates inMay 2005. It is expected that the $750 million The Company's AROs are primarily associated with the decom- credit facility will be renewed prior to its maturity. These credit facilities are being used for working capital, as support for the missioning of its nuclear generation facilities. The changes to the combined commercial paper programs of Dominion, CNG and the Company's AROs during 2004 were as follows:

Company and other general corporate purposes. The $1.5 billion Amount and $750 million credit facilities can also be used to support the (millions) .. issuance of up to $500 million and $200 million of letters of credit, Asset retirement obligations at December 31.2003 $740 respectively.

Obligations settled during the period (1) At December 31, 2004, total.outstanding commercial paper Accretion expense . 4 supported by the joint credit facilities was $573 million, of which Asset retirement obligations at December 31, 2004 $781 the Company's borrowings were $267 million, with a weighted average interest rate of 2.35%. At December 31, 2003, total out-The Company has established trusts dedicated to funding the standing commercial paper supported by previous credit agree-future decommissioning of its nuclear plants. At December 31, ments was $1.44 billion, of which the Company's borrowings were 2004 and 2003, the aggregate fair value of these trusts, consisting $717 million, with a weighted average interest rate of 1.17%.

primarily of debt and equity securities, totaled $1.1 billion and $1.0 -At December 31, 2004, total outstanding letters of credit billion, respectively. 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 out-Note 13. Short-term Debt and Credit Agreements standing letters of credit supported by the joint credit facilities InMay 2004 and 2002, Dominion, Consolidated Natural Gas were $85 million, of which a total of $62 million was issued on the Company (CNG), a wholly-owned subsidiary of Dominion, and the behalf of an unregulated subsidiary of the Company.

20041 Page 45

Notes to Consolidated Financial Statements. Continued Note 14. Long-terin Debt Long-term debt consists of the following:

2004 Weighted Average December 31. Couponsit 2004 2003 (millions, except percentages)

Long-Tenn Debt Secured First and Refunding Mortgage Bondszt:

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 2038X31 - 225 225 Tax-Exempt Financings' 4I:

Variable rate, due 2008 1.33 60 63 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 20075t* 1.75 370 370 Notes Payable to Affiliates Unsecured Junior Subordinated Notes Payable to Affi!iated Trust, 7.37E%. due 2042 - 412 412 Note Payable to Parent, 2.125%, due 2023 - 7.20 220 4,962 5,078 Fairvalue hedge valuation(6l 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 (4) Certain pollution control equipment at the Company's generating facilities has December 31, 2004. been pledged to support these financings. The variable rate tax-exempt financ-(2) Substantially all of the Company's property is subject to the lien of the mrrrt- ings are supported by a stand-alone $200 million three-year credit facility that ne, securing its mortgage bonds. terminates inMay 2006.

13)On December 15, 20083, 225 million of the 4.10% Callable and Puttable (51Represents debt associated with aspecial purpose lessor enitity that iscon-Enhanced SecuritiesSM due 2038 are subject to redemption at par plus accrued solid~ated inaccordaince with RIN 468. The debt isnonrecourse to the Compare interest unless holders of related options exercise rights to purchase and and is secured bthe entis property. plant and equipment of $346 nillionand remarket the notes. $339 million at December31, 2004 and 2003, respectiely.

(61Represents changes in fairvalue of certain fixed rate long-term debt askoated 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 (inmillions):

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 the $400 million realized from the sale of the trust preferred secu-In2002, the Company established a subsidiary capital trust rities and $12 million of common securities that represent the Virginia Power Capital Trust II(trust), a finance subsidiary of the remaining 3%beneficial ownership interest inthe assets held by Company, which holds 100% of the voting interests, sold 16 mil- the capital trust, the Company issued $412 million of its 2002 lion 7.375% trust preferred securities for $400 million, 7.375% junior subordinated notes junior subordinated notes) due representing preferred beneficial interests and 97% beneficial July 30, 2042. The junior subordinated notes constitute 100% of ownership inthe assets held by the trust. Inexchange for 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 Presented below are the series of preferred stock not subject to maturity or if redeemed, prior to maturity. mandatory redemption that were outstanding as of December 31, Under previous accounting guidance, the Company con- 2004:

solidated the trust as preferred securities of subsidiary trust inthe preparation of its Consolidated Financial Statements. In accord- Entitled Issued and Per Share ance with FIN 46R, the Company ceased to consolidate the trust as Outstanding Upon of December 31,2003 and instead reports as long-term debt on its Dividend Shares Liquidation Consolidated Balance Sheet the junior subordinated notes issued (thousands) by the Company and held by the trust. $5.00 107 $112.50 Distribution payments on the trust preferred securities held by 4.04 13 102.27 4.20 15 102.50 the trust are considered to be fully and unconditionally guaranteed 4.12 32 103.73 by the Company, when all of the related agreements are taken into 4.80 73 101.00 consideration. Each guarantee agreement only provides for the 7.05 500 103.18'1 6.98 600 103.150 guarantee of distribution payments on the trust preferred secu- Flex MMP 12/02, Series A 1,250 100.00 rities to the extent that the trust has funds legally and immediately Total 2.59:

available to make distributions. The trust's ability to pay amounts when they are due on the trust preferred securities isdependent I1l Through 7/31A05; $102.82 commencing 8/105; amounts decline insteps there-solely upon the Company's payment of amounts when they are due after to $100.00.

on the junior subordinated notes. If the payment on the junior (2) Through 8/31/05; $102.80 commencing 9/1/05; amounts decline insteps there-after to $100.00.

subordinated notes is deferred, the Company may not make dis-tributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments. Also, during the deferral period, the Company may not Note 16. Shareholder's Equity make any payments or redeem or repurchase any debt securities Common Stock that are equal inright of payment with, or subordinated to, the In2004, as approved by the Virginia State Corporation Commission junior subordinated notes. (Virginia Commission), Dominion made an equity investment inthe Company through the purchase of the Company's common stock.

The Company issued 20,115 shares of its common stock to Note 15. Preferred Stock Dominion for cash consideration of $500 million.

The Company is auithorized to issue up to 10 million shares of Other Paid-In Capital preferred stock, $100 liquidation preference. Upon involuntary In2004 and 2003, the Company recorded $11 million and $21 liquidation, Jissolution or winding-up of the Company, each share million, respectively, of other paid-in capital inconnection with the iseititled to receive $100 per share plus accrued dividernds. Divi- reduction in amounts payable to Dominion.

dends are cumulative.

HoWders of the outstanding preferred stock of tha Company are Accumulated Other Comprehensive Income not entitled -tovoting rights except under certain provisions of the Presented inthe table below is a summary of AOCI by component:

am-ndod and restated articles of incorporation and related provi-December31, 2004 2003 sions of Virginia law restricting corporate action, or upon default in dividends, or inspecial statutory proceedings and as required by (millions)

Net unrealized gains on derivatives-hedging Virginia law (such as mergers, consolidations, sales of assets, activities,notof tax $ 38 $21 dissolution and changes invoting rights or priorities of preferred Net unrealized gains on nucileat decomrnissioning stock.) trust funds. net of tax 91 61 In 2002, the Company issued 1,250 units consisting of 1,000 Total axumulated other comprehensive income $129 $82 shares per unit of cumulative preferred stock for $12.5 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 Note 17. Dividend Restrictions subsequent periods will be determined according to periodic auc-tions. Except during the initial dividend period, and any non-call The 1935 Act and related regulations issued by the Securities and period, the preferred stock will be redeemable, inwhole or inpart, Exchange Commission (SEC) impose restrictions on the transfer on any dividend payment date at the option of the Company. The and receipt of funds by a registered holding company, like Domin-Company may also redeem the preferred stcck, inwhole but not in ion, from its subsidiaries, including the Company. The restrictions part, if certain changes are made to federal tax law which reduce include a general prohibition against loans or advances being the dividends received deduction percentage. made by the subsidiaries to benefit the registered holding com-pany. Under the 1935 Act, registered holding companies and their subsidiaries may pay dividends only 2004 I Page 47

Notes lo Consolidated Financial Statements. Continued from retained earnings, unless the SEC specifically authorizes Note 19. Commitments and Contingencies payments from other capital accounts. In2004, the SEC granted As the result of issues generated inthe ordinary course of busi-relief, authorizing the Company's non-utility subsidiaries to pay ness, the Company is involved inlegal, tax and regulatory proceed-dividends out of capital or unearned surplus insituations where ings before various courts, regulatory commissions and such subsidiary has received excess cash from an asset sale, governmental agencies, some of which involve substantial engaged in a restructuring, or is returning capital to an associate amounts of money. Management believes that the final disposition company.

of these proceedings will not have a material effect on the The Virginia Commission may prohibit any public service Company's financial position, liquidity or results of operations.

company from declaring or paying a dividend to an affiliate, if found not to be inthe public interest. As of December 31, 2004, Long-Tenn Purchase Agreements the Virginia Commission had not restricted the payment of divi- Unconditional purchase obligations as defined by accounting stan-dends bythe Company. dards are those long-term commitments that are noncancelable or Certain agreements associated with the Company's joint credit cancelable only under certain conditions, and that third parties have facilities with Dominion and CNG contain restrictions on the ratio used to secure financing that will provide the contracted goods or of debt to total capitalization. These limitations did not restrict the services. Presented below isa summary of the Company's agree-Company's ability to pay dividends to Dominion or to receive divi- ments as of December 31, 2004:

dends from its subsidiaries at December 31, 2004.

See Note 14 for a description of potential restrictions on divi- 2005 2006 2007 2008 2009 Thereafter Total dend payments by the Company inconnection with the deferral of (millions) distribution payments on trust preferred securities. Purchased electric capacityil) $509 $496 $472 $440 $418 $3,103 $5.438 Note 18. Employee Benefit Plans (1) Commitments represent estimated amounts payable for capacity under power The Company participates ina defined benefit pension plan spon- purchase contracts with qualifying facilities and independent power producers sored by Dominion. Benefits payable under the plan are based Capacity payments under the contracts are generally based'on fixed doll3r primarily on years of service, age and the employee's compensa- 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 tion. As a participating employer, the Company is subject to electrical energy delivered. At December 31, 2004, the present value of the Dominion's funding policy, which isto generally contribute annu- total commitment for capacity payments is$3.4 billion. Capacity payments ally an amount that is inaccordance with the provisions of the totaled $570 million, $611 million and $661 million, and energy payments Employment Retiremnent Income Security Act of 1974. The Compa- totaled $293 million, $289 million and $219 million for 2004,2003, and 2002, respectively.

ny's net periodic pension cost was $40 million, $23 million and $7 million in 2004, 2003 and 2002, respectively. The Company's con- In2004, the Company paid $153 million in cash and assumed tributions to the pension plan were $108 million and $37 million in $213 million of debt inconnection with the termination of three 2003 and 2002, respectively. The Company did not contribute to long-term power purchase agreements and the acquisition of the the pension plan in 2004. related generating facilities used by non-utility generators to The Company participates inplans that provide certain retiree provide electricity to the Company. In connection with the termi-health care and life insurance benefits to multiple Dominion sub- nation of the agreements, the Company recorded after-tax charges sidiaries. Annual premiums are based on several factors such as totaling $43 million. These charges include the reversal of a $167 age, retirement date and years of service. The Company's net million pre-tax contract liability associated with one 6f the termi-periodic benefit cost was $44 million, $44 million and $34 million nated agreements. The contract liability represented the remaining in 2004, 2003 and 2002, respectively. balance of the fair value recorded in October 2003 upon adoption Certain regulatory authorities have held that amounts recovered of SFAS No. 133 Implementation Issue No. C20, Interpretation of in rates for other postretirement benefits inexcess of benefits the Meaning of Not Clearly and Closely Related in Paragraph actually paid during the year must be deposited intrust funds dedi- 10(b) regarding Contracts with a Price Adjustment Feature, (Issue cated for the sole purpose of paying such benefits. Accordingly, the C20). The power purchase agreement, which contained pricing Company funds postretirement benefit costs through Voluntary terms linked to a broad market index, had to be recorded at fair Employees' Beneficiary Associations. The Company's contributions value upon adoption of Issue C20; however, since it qualified as a to health care and life insurance plans were $34 million, $31 million normal purchase and sale contract, no further changes inits fair and $17 million in2004,2003 and 2002, respectively. value were recognized. In2003, the Company paid $154 million for The Company also participates inDorninio.-sponsored the purchase of a generating facility and the termination of two employee savings plans that cover substantially all employees. long-term power purchase agreements with non-utility generators.

Employer matching contributions of $11 million, $10 million and The Company recorded after-tax charges totaling $65 million for

$10 million were incurred in2004, 2003 and 2002, respectively. 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 and remedial action or lb) conduct the remedial investigation and fair values as of the date of acquisition. action and then seek reimbursement from the parties. Each party Inthe fourth quarter of 2004, the Company recorded a $112 can be held jointly, severally and strictly liable for all costs. These million after-tax charge related to its interest ina long-term power parties can also bring contribution actions against each other and tolling contract with a 551 megawatt combined cycle facility seek reimbursement from their insurance companies. As a result, located inBatesville, Mississippi. The Company decided to divest the Company may be responsible for the costs of remedial inves-its interest inthe long-term power tolling contract in connection tigation and actions under the Superfund Act or other laws or with Dominion's reconsideration of the scope of certain activities regulations regarding the remediation of waste. The Company of the Clearinghouse, including those conducted on behalf of the does not believe that any currently identified sites will result in Company's business segments, and Dominion's ongoing strategy significant liabilities.

to focus on business activities within the MAIN to Maine region. In1987, the EPA identified the Company and a number of other The charge is based on the Company's evaluation of preliminary entities as Potentially Responsible Parties (PRPs) at two Superfund bids received from third parties, reflecting the expected amount of. sites located in Kentucky and Pennsylvania. In2003, the EPA issued consideration that would be required by a third party for its its Certificate of Completion of remediation for the Kentucky site.

assumption of the Company's interest inthe contract inthe first Future costs for the Kentucky site will be limited to minor operations quarter of 2005. and maintenance expenditures. Remediation design isongoing for the Pennsylvania site, and total remediation costs are expected to be Lease Commitments inthe range of $13 million to $25 million. Based on allocation for-The Company leases various facilities, vehicles and equipment mulas and the volume of waste shipped to the site, the Company has under both operating and capital leases. Payments under certain accrued a reserve of $2million to meet its obligations at these two leases are escalated based on an index such as the consumer price sites. Based on a financial assessment of the PRPs involved at these index. Future minimum lease payments under noncancelable sites, the Company has determined that it is probable that the PRPs operating and capital leases that have initial or remaining lease will fully pay their share of the costs. The Company generally seeks terms inexcess of one year as of December 31, 2004 are as fol-to recover its costs associated with environmental remediation from lows (inmillions):

third party insurers. At December 31, 2004, any pending or possible 2005 2006 2007 2006 2009 Thereafter Total claims were not recognized as an asset or offset against such

$36 $25 $20 $15 $11 $29 $136 obligations.

Rental expense totaled $40 million, $49 million and $52 million Other EPA Matters for 20C4, 2003 and 2002, respectively, the majority of which is In relation to a Notice of Violation received by the Company in reflected inother operations and maintenance expense. 2000 from the EPA, the Company entered into a Consent Decree settlement in2003 and committed to improve air quality. The Environmental Matters Company has already incurred certain capital expenditures for The Company is subject to costs resulting from a steadily environmental improvements at its coal-fired stations inVirginia increasing number of federal, state and local laws and regulations and West Virginia. The Company continues to commit to additional designed t6 protect human health and the environment. These measures in its current financial plars and capital budget to satisfy laws and regulations can result inincreased capital,,operating and the requirements of the Consent Decree.

other costs as a result of compliance, remediation, containment and -monitoring obligations.

Historically, the Company recovered such costs arising from Nuclear Operations regulated electric operations through utility rates. However, to the NuclearDecommissioning-Minimum FinancialAssurance extent that environmental costs are incurred inconnection with The NRC requires nuclear power plant owners to annually update operations regulated by the Virginia Comniission during the period minimum financial assurance amounts for the future ending December 31, 2010, in excess of the level currently decommissioning of its nuclear facilities. The Company's 2004 included inthe Virginia jurisdictional electric retail rates, the NRC minimum financial assurance amount, aggregated for the Company's results of operations will decrease. After that date, the nuclear units, was $1.3 billion and has been satisfied by a Company may seek recovery through rates of only those environ- combination of guarantees and the funds being collected and mental costs related to regulated electric transmission and dis- deposited inthe trusts.

tribution operations. Nuclearinsurance SuperfundSites The Price-Anderson Act provides the public up to $10.8 billion of From time to time, the Company may be identified as a potentially protection per nuclear incident via obligations required of owners responsible party to a Superfund site. The Environmental Pro- of nuclear power plants. The Price-Anderson Act Amendment of tection Agency (EPA) (or a state) can either (a)allow such a party 1988 allows for an inflationary provision adjustment every five to conduct and pay for a remedial investigation, feasibility study years. The Company has purchased $300 million of coverage from commercial insurance pools with the remainder provided through a 2004/ Page 49

Notes lo Consolidated Financial Statements. Continued mandatory industry risk-sharing program. Inthe event of a nuclear Litigation incident at any licensed nuclear reactor in the United States, the The Company and Dominion Telecom, Inc. (Dominion Telecom)

Company could be assessed up to $100.6 million for each of its were defendants ina class action lawsuit whereby the plaintiffs four licensed reactors, not to exceed $10 million per year per claimed that the Company and Dominion Telecom strung fiber-reactor. There is no limit to the number of incidents for which this optic cable across their land along an electric transmission corridor retrospective premium can be assessed. without paying compensation. The plaintiffs sought damages for The Price-Anderson Act was first enacted in 1957 and has been trespass and unjust enrichment,' as well as punitive damages renewed three times-in 1967, 1975 and 1998. The Price- from the defendants. InApril 2004, the parties entered into a Anderson Act expired on August 31, 2002, but operating nuclear settlement agreement that was subsequently approved by the reactors continue to be covered by the law. Congress is currently court inJuly 2004. Under the terms of the settlement a fund of holding hearings to reauthorize the legislation. $20 million was established by the Company to pay claims of The Company's current level of property insurance coverage current and former landowners as well as fees of lawyers for the

($2.55 billion each for North Anna and Surry) exceeds the NRC's class. Costs of notice to the class and administration of claims will minimum requirement for nuclear power plant licensees of $1.06 be borne separately by the Company. The settlement agreement billion per reactor site and includes coverage for premature resulted inan after-tax charge of $7million inthe first quarter of decommissioning and functional total loss. The NRC requires that 2004.

the proceeds from this insurance be used first to return the reactor.

Guarantees and Surety Bonds to and maintain it ina safe and stable condition and second to As of December 31; 2004, the Company had issued $16 million of decontaminate the reactor and station site in accordance with a guarantees to support commodity transactions of subsidiaries. The plan approved by the NRC. The Company's nuclear property Company had also purchased $11 million of surety bonds for insurance is provided by Nuclear Electric Insurance Limited (NEIL),

various purposes, including providing worker compensation a mutual insurance company, and is subject to retrospective coverage and obtaining licenses, permits, and rights-of-way. Under premium assessments inany policy year inwhich losses exceed the terms of surety bonds, the Company is obligated to indemnify the funds available to the insurance company. The maximum the respective surety bond company for any amounts paid.

assessment for the current policy period is $52 million. Based on the severity of the incident, the board of directors of the Compa- Indemnifications ny's nuclear insurer has the discretion to lower or eliminate the As part of commercial contract negotiations in the normal course maximum retrospective premium assessment. The Company has of business, the Company may sometimes agree to make payments the financial responsibility for any losses that exceed the limits or to compensate or indemnify other parties for possible future for which insurance proceeds are not available because they must unfavorable financial consequences resulting from specified first be used for stabilization and decontamination. events. The specified events may involve an adverse judgment in a The Company purchases insurance from NEIL to cover the cost lawsuit or the imposition of additional taxes due tu a change in tax of replacement power during the prolonged outage of a nuclear law or interpretation of the tax law. The Company isunable to unit due to direct physical damage of the unit. Under this program, develop an estimate of the maximum potential amount of future the Company is subject to a retrospective premium assessment for payments under these contracts because events that would obli-any policy year inwhich losses exceed funds available toNEIL The gate the Company have not yet occurred or, if any such event has current policy period's maximum assessment is $20 million. occurred, the Company has not been notified of its occurrence.

The North Anna Power Station isjointly owned by Old However, at December 31, 2004, management believes future Dominion Electric Cooperative, as discussed inNote 9.The co- payments, if any, that could ultimately become payable under owner is responsible for its share of the nuclear decommissioning these contract provisions, would not have a material impact on its obligation and insurance premiums, including any retrospective results of operations, cash flows or financial position.

premium assessments and any losses not covered by insurance.

Stranded Costs Spent Nucfear Fuel In1999, Virginia enacted the Virginia Restructuring Act that estab-Under provisions of the Nuclear Waste PolicyActof 1982, the lished a detailed plan to restructure Virginia's electric utility Company has entered into a contract with the DOE for the disposal industry. Under the Virginia Restructuring Act, the generation of spent nuclear fuel. The DOE failed to begin accepting the spent portion of the Company's Virginia jurisdictional operations is no nuclear fuel on January 31, 1998, the date provided by the Nuclear longer subject to cost-based regulation. The legislation's dereg-Waste Policy Act and by the Company's contract with the DOE. In ulation of generation was an event that required the dis-January 2004, Dominion and the Company filed a lawsuit inthe continuance of SFAS No. 71, Accounting for the Effects of Certain United States Court of Federal Claims against the DOE incon-nection with its failure to commence accepting spent nuclear fuel. Types of Regulation, for the Virginia jurisdictional portion of the The Company will continue to safely manage its spent fuel until it Company's generation operations in 1999. InApril 2004, the is accepted by the DOE. 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 Note 20. Fair Value of Financial Instruments December 31, 2010, unless modified or terminated earlier under. Substantially all of the Company's financial instruments are the Virginia Restructuring Act. Inaddition to extending capped recorded at fair value, with the exception of the instruments rates, the amendments: described below that are reported based on historical cost. Fair

• Lock inthe Company's fuel factor provisions until the earlier of values have been determined using available market information July 1,2007 or the termination of capped rates; and valuation methodologies considered appropriate by manage-

• Provide for a one-time adjustment of the Company's fuel factor, ment. The financial instruments' carrying amounts and fair values effective July 1. 2007 through December31, 2010 (unless as of December 31, 2004 and 2003 were as follows:

capped rates are terminated earlier under the Virginia. .

Restructuring Act), with no adjustment for previously incurred 2004 2003 over-recovery or under-recovery, thus eliminating deferred fuel Estimated Estimated accounting for the Virginia jurisdiction; and Carrying Fair Carrying Fair Amount Value(M) Amount Value(')

• End wires charges on the earlier of July 1,2007 or the termination of capped rates, consistent with the Virginia Imillions)

Long-term debt $4,338 $4,455 $4,437 $4,641 Restructuring Act's original timetable. Junior suhoidinated Wires charges, also known as competitive transition charges, are notes payable to affiliated trust 412 445 412 454 permitted to be collected by utilities until July 1.2007, under the Virginia Note payable to parent 220 224 220 222 Restructurng Act The Company has agreed to forego the collection of wires charges in2005; and as such, Virginia customers will not pay the (1)Fair value is estimated using market prices, where available, and interest rates fee if they switch from the Company to a different service provider. currently available for issuance of debt with similar terms and remaining matur-ities. The carrying amount of debt issues with short-term maturities and variable The Company believes capped electricretail rates and,where rates repriced at current market rates is a reasonable estimate of their fair value.

applicable, wires charges provided under the Virginia fRestructuring Act provide an opportunity to recover a portion of its potentially stranded costs, depending on market prices of electricity and other Note 21. Ctredit Risk factors. Stranded costs are those generation-related costs incurred or commitments made by utilities under cost-based regulation that may Credit risk is the risk of financial loss to the Company if counter-not be reasonably expected to be recovered ina competitive market parties fail to perform their contractual obligations. In order to Inthe capped rate environment, the Company remains exposed minimize overall credit risk, Dominion and its subsidiaries, to numerous risks, including, among others, exposure to potentially including the Company, maintain credit policies, including the stranded costs, future environmental compliance requirements, evaluation of counterparty financial condition, collateral require-changes intax laws, inflation and increased capital costs. At ments and the use of standardized agreements that facilitate the December 31, 2004, the Company'r exposure to potentially netting of cash flows associated with a single counterparty. In stranded costs included: long-term power purchase contracts that addition, counterparties may make available collateral, including could ultimately be determined to be above market; gererating letters of credit or cash held as margin deposits, as a result of plants that could possibly become uneconomic ina deregulated exceeding agreed-upon credit limits or may be required to prepay environment and unfunded obligations for nuclear plant decom- the transaction. Amounts reported as margin deposit liabilities missioning and postretirement benefits not yet recognized inthe represent funds held bythe Company that resulted from various financial statements. trading counterparties exceeding agreed-upon credit limits estab-lished by the Company. Amounts reported as margin deposit assets represent funds held on deposit by various trading counter-parties 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 with related changes included inearnings, except to the extent transmission services to a diverse group of customers, including designated as cash flow hedges.

residential, commercial and industrial customers as well as rural Presented below are affiliated transactions recorded in electric cooperatives and municipalities. Credit risk associated operating revenue and operating expenses:

with trade accounts receivable from energy consumers is limited Year Ended December 31, due to the large number of customers. In addition, the Company enters into contracts with various companies inthe energy industry 2004 2003 2002 for purchases and sales of energy-related commodities, including (millions) natural gas and electricity inits energy trading and risk manage- Purchases of natural gas, gas transportation and ment activities. These transactions principally occur inthe North- storage services from affiliates $1,152 $737 $162 Sales of natural gas to affiliates 701 673 279 east, Midwest and Mid-Atlantic regions of the United States; Sales of electricity to affiliates - 10 1 however, management does not believe that this geographic Net realized gains (losses) on affiliated commodity concentration contributes significantly to the Company's overall derivative contracts (11) 111) 45 exposure to credit risk.

The Company's exposure to credit risk is concentrated primarily The Company's Consolidated Balance Sheets include derivative within its energy trading and risk management activities, as the assets with affiliates of $84 million and $86 million at December 31, Company transacts with a smaller, less diverse group of counter- 2004 and 2003, respectively, and derivative liabilities with affili-parties and transactions may involve large notional volumes and ates of $34 million and $65 million at December 31, 2004 and potentially volatile commodity prices. At December 31, 2004, gross 2003, respectively.

credit exposure related to these transactions totaled $695 million, Dominion Resources Services Inc. (Dominion Services) provides reflecting the unrealized gains for contracts carried at fair value accounting, legal and certain administrative and technical services plus any outstanding receivables (net of payables, where netting to the Company. The Company provides certain services to affili-agreements exist), prior to the application of collateral. After the ates, including charges for facilities and equipment usage. The application of collateral, the Company's credit exposure totaled cost of these services is as follows:

$677 million. Of this amount, investment grade counterparties Year Ended December 31.

represent 97% and no single counterparty exceeded 10%. The credit exposure amounts exclude amounts receivable from affili- 2004 2003 2002 ated companies. Imillions)

Services provided to the Company by Dominion Services $276 $290 $267 Services provided by the Company to Note 22. Related Party Transactions affiliates 26 27  : 29 The Company engages inrelated party transactions primarily with affiliates (Dominion subsidiaries). The Company's accounts ruceiv- The Company assigned energy contracts to a Dominion sub-able and payable balances with affiliates are settled based on sidiary in2003, with regulatory approval, inconnection with contractual terms on a monthly basis, depending on th3 natuie of Dominion's plan to transfer certain wholesale power mare:tirg the underlying transactions. The Company isincluded inDomin- activities that occur outside of the Company's service territory. The ion's consolidated federal income tax return and participates in Company received $13 million representing the net fair value of certain Dominion benefit plans. The significant related party trans- the contracts transferred. The transferred contracts involve the actions are disclosed below. delivery of electric energy for physical power purchases of 17 million megawAatt-hours and saies of 19 million megawatt-hours Transactions with Affiliates for 2003 through 2006.

The Company, through an unregulated subsidiary, transacts with The Company assigned a sales contract to a Dominion sub-affiliates for certain quantities of natural gas and other commod-sidiary in2003, involving the delivery of approximately 6 million ities at market prices inthe ordinary course of business. Through megawatt-hours of wholesale electric energy in2003, declining by this unregulated subsidiary, the Company isalso involved infacili-approximately 0.5 million megawatt-hours annually from 2004 tating Dominion's enterprise risk management by entering into certain financial derivative commodity contracts with affiliates. through 2006 to 4,000 megawatt-hours in2008.

These contracts, which are principally comprised of commodity Transactions with Dominion swaps, are used by Dominion subsidiaries to manage commodity The Company leases its principal office building from Dominion price risks associated with purchases and sales of natural gas. As under an agreement that expires in2008. The lease agreement part of Dominion's enterprise risk management, the Company was approved by the Virginia Commission and is accounted for as generally manages such risk exposures by entering into offsetting a capital lease. The capitalized cost of the property under the derivative instruments with third parties. The Company reports lease, net of accumulated amortization, was approximately both affiliated and third party derivative instruments at fair value, $8million 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 $3million ments' core earnings. As a result certain specific items attributable each in2004, 2003 and 2002. to those segments are not included inprofit measures evaluated by The Company and its subsidiaries have borrowed funds from executive management inassessing the segment's performance or Dominion. At December 31, 2004 and 2003, outstanding borrow- allocating resources among the segments. These specific items are ings, net of repayments, under a short-term demand note totaled reported inthe Corporate and Other segment and in2004 include:

$645 million and $154 million, respectively, and a long-term note

• Charges reflecting the Company's valuation of its interest ina totaled $220 million for both periods. Interest charges incurred by long-term power tolling contract and the termination of three the Company related to these borrowings were $11 million and $1 long-term power purchase agreements; million in2004 and 2003, respectively.

• A charge related to a class action lawsuit settlement; and In2004, as approved by the Virginia Commission, Dominion

• A benefit to adjust restoration expenses accrued in2003 made an equity investment inthe Company through the purchase associated with Hurricane Isabel.

of the Companys common stock. The Company issued 20,115 2003 specific items include:

shares of its common stock to Dominion for cash consideration of

• Cumulative effect of changes inaccounting principles;

$500 million. The Company used the proceeds in part to pay down

• Incremental restoration expenses associated with Hurricane its $345 million short-term demand note from Dominion.

In2004 and 2003, the Company recorded $11 million and $21 Isabel; 1

• Charges for the termination of two long-term power purchase million, respectively, of other paid-in capital in connection with the agreements and restructuring of certain electric sales reduction inamounts payable to Dominion.

contracts; and Other Related Party Transactions

• Severance costs for workforce reduction.

Upon adoption of FIN 46R for its interests inspecial purpose enti-The Company reported no specific items inCorporate and Other ties on December 31,2003, the Company ceased to consolidate attributable to its operating segments in2002.

the Virginia Power Capital Trust II,a finance subsidiary of the During the fourth quarter of 2004, the Company performed an Company. The junior subordinated notes issued by the Company evaluation of its Clearinghouse trading and marketing operations, and held by the trust are reported as long-term debt. The Company.

which resulted in a decision to exit certain energy trading activities reported $31 million of interest expense on the junior subordinated and instead focus on the optimization of company assets. Begin-notes payable to affiliated trust in2004 and $30 million of dis-ning in2005, all revenue and expenses from the Clearinghouse's tributions of mandatorily redeemable trust preferred securities in optimization of company assets will be reported as part of the 2003.

results of the business segments operating the related assets, in order to better reflect the performance of the underlying assets.

Note 23. Operating Segments As a result of these changes, 2004 and 2003 results now reflect The Company Isorganized primarily on the basis of products and revenue and expenses associated with the Clearinghouse's coal services sold inthe United States. trading and marketing activities inthe Generation segment.

The Company manages its operations through the three Intersegment sales and transfers are based on underlying operating segments.: ... contractual arrangements and agreements and may result in inter-Generation includes the Companys portfolio of electric segment profit or loss.

generating facilities, power purchase agreements, marketing of its excess generation resources and coal trading and marketing activities.

Energy includes the Company's electric transmission oper-ations and energy trading and risk managerr.ent 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 isallocated among the three segments for management reporting based on an unbundied rate methodology.

Inaddition, the Company also reports Corporate and Other func-tions 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 seg-2004/ Page 53

Notes to Consolidated Financial Statements. Continued The following table presents segment information pertaining to the Company's operations:

Corporate Consolidated Generation Energy Delivery and Other Eliminations 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) 17.319 2003 Operating revenue S3,795 $ 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 Totalassets(atDecember31) 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)

Asummary 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 afair statement of the results for the interim peri-ods. Results for interim periods may fluctuate as aresult of weather conditions, changes inrates and other factors.

First Second Third Fourth Quarter Quarter Quarter 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 inaccounting principles 306 133 200 (57) 582 Net income (loss) 390 133 200 (162) 561 Balance available forcommon stock 387 130 196 (167) 546 The 2004 results include the impact of the following significant The 2003 results include the impact of the following significant item: items:

• Fourth quarter results include a $112 million after-tax charge

• First quarter results include a $84 million net after-tax gain reflecting the Company's valuation of its interest ina long-term representing the cumulative effect of adopting SFAS No. 143 power tolling contract that is subject to a planned divestiture in and EITF 02-3, as described in Note 3; the first quarter of 2005.

2004/ Page 54

Notes to Consolidated Financial Statements, Continued

• Third quarter results include $80 million of after-tax Item 9.Changes in and Disagreements incremental restoration expenses associated with Hurricane

- Isabel; and with Accountants on Accounting and

• Fourth quarter results include $105 million after-tax loss Financial Disclosure representing the cumulative effect of adopting Issue C20 and None.

FIN 46R, as described in Note 3, and $42 million of after-tax incremental restoration expenses associated with Hurricane Isabel. 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 con-cluded that the Company's disclosure controls and procedures are effective. There were no changes inthe 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 inspecial purpose entities referred to as SPEs. As a result, the Company has included in its Consolidated Financial Statements the SPE described inNote 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 ertity.

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 iselected annually, isas follows:

You First Principal Occupation for Last Five Years and Elected as Name and Age Directorships in Public Corporations Diretors Thos. E.Capps (69) Chairman of the Board of Directors and Chief Executive Officer of Dominion from 1986 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).

Thomas F.Farrell. 11(501 President and Chief Operating Officer of Dominion from January 2004 to date; 1999 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.

Thomas N.Chewning (59) Executive Vice President and Chief Financial Officer of Dominion from May 1999 to 1999 data; Executive Vice President and Chief Financial Officer of Consolidated Natural Gas Company from January 2000 to date.

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-c-Prtf3lio Management of Virginia Electric and Power Company from January 2000 to December 2002.

Mark F.McGettrick (471 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; SeniorVice 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 NameandAge usisssExpeiene Pst Fve ear 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 CompanyfromApril 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; SeniorVice 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 betv.'een any of the persons named inresponse to Item 10.

InMay 2004, Domirio~l sold its teiecumniiiunications subsidiary. Dominion lelecom, 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 Bank-ruptcy code. Messrs. Johnson. Hetzsr 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 Cods 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 telephloning 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 SummaryCompensation Table below includes compensation paid by the Company for services rendered in2004,2003 and 2002 to the Chief Execu-tive Officers and the four other most highly compensated executive officers as determined under the SEC executive compensation disclosure rules.

Summary Compensation Tablet)

Annual Compensation Long Term Compensation Awards Payouts Restricted Securities Other Annual Stock Underlying LTIP All Other Name and Principal Position Year Salarym Bonus§ t Compensation AwardsM4 Options/SARsml Payouts Compensationr JayL Johnson 2004 176,364 - 73,271(41 302,955 - - 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 - 57,876S) 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 - 12,247J 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 JimmyD. Staton 2004 148,531 54.930 31,6981% 142,760 ' - - 51,942 Senior Vice President-Operations 2003 270,400 135200 32,516 259,386 - - 53,267 2002 253,604 126,802 31,717 -- - - 46,023 EdwardJ. Rivas 2004 167,210 - 41,2925 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 20D4 138,528 35,758 8,292P 150,011 - - 28,588 Senior Vice President-Nuclear Operations 2003 170,832 120,212 5.907 184,631 - - 25,228 2002 109,229 79,5,7 4,306 28.313 17,297 - 9,748 DavidA Christian 2004 171,904 - 23,142M 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 (11The executive officers included inthis table may perform services for more than one subsidiary of Dominion. Compensation for the individuals listed inthe table reflects only that portion which isallocated to the Company for each of the years reported and differences from year to year may reflect changes inallocation levels rather than changes insalary.

(2) Salary-Amounts shown may include Placation sold back to the Company.

(3) No bonuses were earned in2004 under the Company's profit sharing plan. The amwunts inthis column for 2004 represent a one-time cash award to Mr. Staton for addi-tional duties he assumed in2003-2004, 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 busi-ness expenses, the loan program subsidy and other costs, and personal use of the corporate aircraft. The tax reinbursement amounts are as follows: Johnsonf$40,114Y, and McGettrick ($34,1791. The amounts inthis column also include income related to perquisites provided under the programs described under Executive Perquisites and Other Benefits inthis 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 in2004). None of these execu.i-tive officers had perquisites valued at $50,000 or more in2002 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 inexcess of S50,000 or 10% of their total cash compesrsaticn. 1he amounts listed inthese columns are tax reimbursement amounts. -

(6)Restricted Stock Awards-The number and value of each exocutive's aogregated restricted stock holdings at year-end, based on aDecember 31, 2004 closing price of

$67.74 per share, were as follows:

Number of Officer Restricted Sharesel 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.

(71 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 forwhole life insurance policy.

2004I/Page 58

Executive Employee Stock Loan Savings Plan Executive Employee Program Match Supplemental Savings Interest Above IRS ife Officer Plan Match Subsidy Limits Insurance JayL Johnson 3,144 33,137 2,147 22,967 Mark F.McGettrick 5,217 36,458 i 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 WilliamR.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 Yearl{.

And FY-End Option/SAR Values Number of Securities Underlying Unexercised Value of Unexercised In-the-OpbionslSARs Money Options/SARs At FY-End At FY-End(x Shares Acquired on Value Exercise RealizedrZ) Exercisable Unexercisable Exercisable Unexercisable JayL 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 Wlliam R.Matthews :18,101 376,940 35,915 17,957 210,280 105,140 Daid A Christian - 24,056 480,407 70,0G4 35,046 545.329 272.660 (11The 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 inthe table reflect only that portion which is allocated to the Company. These option exercises were made inconnection with the prepayment of executive loans under the Stock Purchase and Loan Program, with the proceeds referred to above being used first land 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 Base Salary and Annual Incentive The Company targets base pay and annual incentive pay at or The Company's executive compensation program is regularly slightly above market median for similar positions at companies in reviewed by the Organization, Compensation and Nominating our executive labor market. Generally, officers did not receive base Committee of the Dominion Board (Dominion's Committee) and its salary increases in 2004 (other than for promotions or compelling recommendations are subsequently referred.to the Company's market reasons). Instead, the Dominion Committee focused on Board of Directors. Dominion's Committe3 acts independently of long-term awards.

management and works with a nationally recognized independent Under the annual incentive program, 'target awards' are estab-consultant. Dominion's executive cornpensaticn program is lished for each executive officer. These target awards are designed to provide its executives with competitive salaries, expressed as a percentage of the individual executive's base bonuses, long-term incentives and benefits that align their finan-salary (for example, 40% x base salary). The target award is the cial success to the financial success of its shareholders and the amount of cash that will be paid at year-end if the executive Company.

achieves 100% of the goals established at the beginning of the This strategy includes placing a substantial portion of executives' year. A 'threshold"-or minimum acceptable level of corporate pay at risk, including tying compensation to the achievement of financial performance-is established, and if this threshold is not strategic financial performance measures-paying for performance.

met, no executive receives an annual incentive payment. Actual The Dominion Committee also ensures that Dominion maintains a bonuses, if any, are based on a pre-established formula and may balanced program to provide the appropriate mix of base salary and exceed 100% of the target award if performance expectations are annual and long-term incentives.

exceeded. Because Dominion did not achieve the threshold target The 2004 program focused on long-term compensation and for 2004, no bonuses were paid under the annual incentive pro-annual incentives. The Dominion Committee also permitted and gram.

encouraged voluntary prepayments of loans under its grand-fathered stock purchase program, reimbursing officers for the Long-term Incentives additional interest and other costs incurred as a result of any Equity compensation continues to be viewed as the strongest form prepayments. of long-term incentive as it helps to underscore an individual's 2004/ Page 59

commitment to the Company while still rewarding performance. credited service if he serves as an officer until age 60. Mr. Rivas is During 2004, performance-accelerated restricted stock was the being provided with 30 years of credited service since he has only method used to grant equity to executives. All shares were reached the age of 60. Each of the named executives inthe Sum-granted at 100% of the fair market value of Dominion's stock price mary Compensation Table, except for Messrs. Johnson and Koonce, on the date of grant. will have 30 years of credited service at age 60. Mr. Staton will have 30 years of credited service at age 601/.z Stock Ownership Guidelines Since 2000, Dominion has had ownership guidelines for manage- Benefit Restoration Plan ment inorder to emphasize the importance of aligning the inter- The Internal Revenue Code imposes certain limits related to Pen-ests of management and Dominion shareholders. The Company sion Plan benefits. Any resulting reduction inan executive's Pen-provides tools to assist management inobtaining their desired sion Plan benefit will be compensated for under the Restoration ownership levels. Plan.

This Plan was frozen as of December 31,2004 and the New Dominion Resources, Inc. Benefit Restoration Plan was implemented on January 1,2005.

Stock Ownership Guidelines There was no change inthe amount of benefits as a result of this change.

Multiple of Salary/

Position No. of Shares Executive Supplemental Retirement Plan CEO/COO-Operating Companies 5X /35,000 The Supplemental Plan provides an annual retirement benefit Senior Vice President ' 4x/20,000 Vice President 3x/ 10.tO equal to 25% of a participant's final cash compensation (base pay plus target annual incentive). To retire with full benefits under the Retirement Plans Supplemental Plan, an executive must be 55 years old and have The table below shows the estimated annual straight life benefit been employed by the Company for at least five years. Benefits that the Company would pay to an employee at normal retirement under the plan are provided either as a lump sum cash payment at (age 65) under the benefit formula of the Pension Plan. 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 2004 Estimated Annual Benefits Payable Upon Retirement will receive a lifetime benefit if he serves as an officer until age

50. Based on 2004 cash compensation, the estimated annual Plan benefit under this plan for executives named inthe Summary Creditd Years of Service Compensation Table are: Mr. Johnson-$79,364; Mr.

Fnal McGettrick-$93,044; Mr. Koonce-$40,687; Mr. Staton-Average $55,699; Mr. Rivas-$62,704; Mr. Matthews-$51,948: Mr.

Earnings 15 20 25 30 Christian-$73,059.

S185,00o $ 49,930 $ 66,540 $ 83,150 $ 99,760 This Plan was frozen as of December 31, 2004 and the New

$200,0o00 54,480 72,610 90.740 108,880

$250,00 69,620 92,820 116.030 139,220 Executive Supplemental Retirement Plan was implemented on 30oo 84.760 113,040 141,310 169,580 January 1,2005. There was no change inthe amount of benefits

$350000 99.,890 133,240 166,580 199,940 as a result of this change.

$400,00 115.030 153,460 191,880 230,320 Other Executive Agreements and Arrangements Benefits under the Pension Plan are based on: Companies that are ina rapidly changing industry such as ours

• highest average base salary over a five consecutive year period require the expertise and loyalty of exceptional executives: Not during the ten years preceding retirement only isthe business itself competitive, but so is the demand for

• years of credited service; such executives. Inorder to secure the continued services and

• age at retirement; and focus of key management executives, the Company has entered

• the offset of Social Security benefits. into certain agreements with them, including those named inthe Summary Compensation Table.;

The Company provides a Special Retirement Account (SRA)

In2004, Mr. Rivas entered into a letter agreement with the feature to the Pension Plan. This account is credited with two-company, agreeing to postpone his retirement until April.1, 2005 in percent of an employee's base salary earned each year. Account consideration for a lump sum cash bayment at retirement equal to balances are credited with earnings based on the 30-year Treasury the value of his 2004 performance-accelerated restricted stock rate and may be taken as a lump sum or an annuity at retirement.

award. Mr. Rivas agreed to forgo any long-term awards in2005. .

The above table includes the effect of SRA balances converted to Mr. Christian and Mr. Matthews have entered into Supple-an annual annuity.

mental Agreements with Dominion whereby they have also agreed Inaddition, Mr. Johnson will receive 20 years of credited service not to compete with the activities of Dominion nor solicit any after 10 years of continuous employment. Mr. McGettrick will Dominion employees inconsideration of their receipt of enhanced receive 5 years of additional age and service if he serves as an benefits under the Supplemental Retirement Plans described officer until his 50th birthday. Mr. Matthews will receive 30 years of above.

2004/Page 60

Special Arrangements stock solely for the purpose of paying off their loans under the Executives named inthe Summiary Compensation Table have programs. Every officer of the Company that had a loan out-entered into employment continuity agreements, which provide standing prepaid their loan in 2004, exercising options and selling benefits inthe event of a change in control. Each agreement has a shares to the extent necessary to pay off the loan balance and three-year term and isautomatically extended for an additional cover any resulting tax liability.

year, unless cancelled by the Company. During 2001, the stock ownership guidelines for executives The agreements provide for the continuation of salary and were reconfirmed and the Executive Stock Purchase Tool Kit was benefits for a maximum period of three years after either (1)a implemented. The Tool Kit consists of a variety of programs to change in control, (2)termination without cause following a encourage ownership of Dominion stock by executives who could change in control, or (3)a reduction of responsibilities, salary and not participate inthe Executive Stock Purchase and Loan programs.

incentives following a change incontrol (if the executive gives 60 Executives who participate in one or more of the Tool Kit programs days notice). Under the agreements executives would receive the to achieve their stock ownership target levels receive "bonus following: (1)an annual base salary not less than the executives' shares' for up to twenty-five percent of the value of their invest-highest annual base salary during the twelve months preceding the ments in Dominion stock. The Tool Kit previously included the change of control, (2)an annual bonus not less than the highest availability of loans guaranteed by Dominion; but this alternative maximum annual bonus available to the executives during the has been omitted for the reasons discussed above.

three years preceding the change of control and (3)continued Perquisites and Other Benefits eligibility for awards under company incentive, savings and benefit The Company offers a limited number of perquisites to its execu-plans provided to senior management. Inaddition, any outstanding tives: company car allowance, afinancial planning allowance and a stock options and other forms of stock awards will fully vest upon club membership benefit. Furthermore, certain senior and nuclear a change in control. Upon a covered executive's death or disability, executives are provided with security systems at their home resi-or in the event the executive isterminated without cause, the dence. While the Company does not consider this service to be a agreement provides for a lump sum severance payment equal to perquisite, but instead views its security program as serving a three times base salary plus annual bonus, together with the full business need for a limited number of executives, the Company will vesting of benefits under the company's benefit plans. If a covered begin counting these costs inits calculation of perquisites for 2004 executive is terminated without cause, the executive also will or until further guidance isoffered by the SEC.

receive full vesting of any outstanding stock options and five years Similarly, the Company provides its executives with up to of additional credit for age and service. The agreements indemnify

$1,000 inreimbursements for annual physical exams expenses that the executives for potential penalties related to the Internal may not be covered otherwise. The Company does not consider Revenue Code and fees associated with the enforcement of the this benefit to be a perquisite and amounts relating to it are not agreements. If an executive isterminated for cause, the agree-included inthe Summary Compensation Table. Finally, as disclosed ments are not effective.

in Footnote 4 to the Summary Compensation Table, in limited For purposes of the continuity agreements described above, a circumstances the Company executives may have use of the change of control shall be deemed to have occurred if (i) any company planes for personal travel.

person or group becomes a beneficial owner of 20% or more of the combined votihg power of Dominion voting stock or (ii) as a direct Compensation ot Directors or indirect result of, or in connection with, a cash tender or All of the Directors, who are officers of the Company or Dominion, exchange offer, a merger or other business combination, a sale of do not receive any compensation for services they provide as assets, or contested election, the Directors constituting the directors.

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 Lompany loans or guarantees to executives under the Sarbanes-Oxley Act of 2002, Dominion has ceased its pro-grams involving the company guaranty of a third party loan to executives for the purpose of acquiring company stock. Inthe fall of 2003, the OCN Committee authorized executives with loans to exercise previously granted options or to sell shares of Dominion 2004/ Page 51

I1 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 con-solidated 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 December31, 1993, File No. 1-2255, incorporated by reference).

10.3 PJM South ImplementationAgreement between Virginia Electric and PowerCompanyand 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 10-0 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 10-0 for the quarter ended September 30, 2003, File No. 1-8489, incorporated by reference).

10.6 Form of Settlement Agreement inthe 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 NewJersey, 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 Ma,-ch 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 31,1 991, File No. 1-2255, incorporated by reference).

10.9* Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, 1997, as amended and restated effective July20, 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-Kfor the fiscal year ended December 31, 2002, File No. 1-2255, incorporated by reference).

10.11^ Form of Employment ContinuityAgreement for certain officers of the Company, amended and restated July 15, 2003 (Exhibit 10.1, Form 10-0 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 10-0 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 agreementdated July29, 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.

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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: Isi 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 Tide

/s/ THOS. E.CAPPs Chairman of the Board of Directors Thos. E. Capps

/s/ THOMAS N.CHEWNING Director Thomas N. Chewning Is! THOMAS F.FARRELL, II Director Thomas F. Farrell, II

/sl JAY L JOHNSON President and Chief Executive Officer Jay L Johnson

/S/ PAUL D.KoONcE Chief Executive Officer-Energy Paul D. Koonce Is! MARK F.McGETTRIcK President and Chief Executive Officer-Generation Mark F. McGettrick

/s! G.ScoTT HErzrEf Senior Vice President and Treasurer (Principal Financial Officer)

G. Scott Hetzer

/s/ STEvENA. RoGriS Vice President (Principal Accounting Officer)

Steven A. Rogers 2004 /Page 66