ML051050476

. 2. and 3 and ISFSI Annual Reporting of Financial Information

ML051050476
Person / Time
Site:	Millstone
Issue date:	04/01/2005
From:	Matthews W Dominion Nuclear Connecticut
To:	Document Control Desk, NRC/FSME
References
05-200
Download: ML051050476 (114)

Text

Dominion Nuclear Connecticut, Inc. D Millstone Power Station DominionU Rope Ferry Road Waterford, CT 06385 April 1, 2005 Director of Nuclear Reactor Regulation Serial No.05-200 U. S. Nuclear Regulatory Commission NLOS/vlh Washington, D. C. 20555-0001 Docket Nos. 50-245/336/423 72-47 License Nos. DPR-21/65 NPF-49 DOMINION NUCLEAR CONNECTICUT, INC.

MILLSTONE POWER STATION UNITS 1. 2. AND 3 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 October 20, 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

SN 05-200 Docket Nos. 50-245/336/423, 72-47

Subject:

Price-Anderson Submittal Page 2 of 2 cc: U. S. Nuclear Regulatory Commission Region I 475 Allendale Road King of Prussia, PA 19406-1415 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555-0001 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. V. Nerses U. S. Nuclear Regulatory Commission One White Flint North 11555 Rockville Pike Rockville, MD 20852-2738 Mr. A. B. Wang U. S. Nuclear Regulatory Commission One White Flint North 11555 Rockville Pike Rockville, MD 20852-2738 Mr. G. F. Wunder U. S. Nuclear Regulatory Commission One White Flint North 11555 Rockville Pike Rockville, MD 20852-2738 Mr. R. Prince U. S. Nuclear Regulatory Commission Region I 475 Allendale Road King of Prussia, PA 19406-1415 Mr. S. M. Schneider NRC Senior Resident Inspector Millstone Power Station

Dominion Resources, Inc.

Consolidated Statements of Income Year Ended December 31, 2004 2003 (millions)

Operating Revenue $ 13,972 12,078 Operating Expenses Electric fuel and energy purchases, net 2,162 1,667 Purchased electric capacity 587 607 Purchased gas, net 2,927 2,175 Liquids, pipeline capacity and other purchases 1,007 468 Other operations and maintenance 2,748 2,908 Depreciation, depletion and amortization 1,305 1,216 Other taxes 519 476 Total operating expenses 11,255 9,517 Income from operations 2,717 2,561 Other income (loss) 186 (40)

Interest and related charges:

Interest expense 811 849 Interest expense-junior subordinated notes payable to affiliated trusts 112 -

Distributions-mandatorily redeemable trust preferred securities - 111 Subsidiary preferred dividends 16 15 Total interest and related charges 939 975 Income before income taxes 1,964 1,546 Income tax expense 700 597 Income from continuing operations before cumulative effect of changes in accounting principles 1,264 949 Loss from discontinued operations (net of income tax benefit of $4 and expense of $15, in 2004 and 2003, respectively) (15) (642)

Cumulative effect of changes in accounting principles (net of income taxes of S7) - 11 Net Income $ 1,249 $ 318

DOMINION RESOURCES, INC.

2005 ESTIMATED INTERNAL CASH FLOW (Millions of Dollars)

January April July October Estimated through through through through 2005 March June September December Total Cash receipts $ 4,490 $ 3,591 $ 3,806 $ 3,894 $ 15,781 Less:

Cash for operations 3,020 2,385 2,346 2,491 10,241 Taxes 428 294 380 359 1,462 Interest 224 210 213 219 867 Dividends 231 234 234 235 935 Decommissioning trust 9 113 9 9 140 Changes in working capital/other (1,266) (26) 77 244 (972)

Total cash flow (') $ 1,844 $ 381 $ 547 $ 336 $ 3,108

(') Before financing and construction requirements

DOMINION RESOURCES, INC 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.

Ira I o Thomas R. Bean Vice President - Financial Management NQOARIAL 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 0 My commission expires: August 31, 2007

Dominion Resources, Inc.

Statement Based on the company's 2005 approved budget, the company estimates that 2005 Plant construction and other property additions to be $1,5721 million. Maturity of securities net of refinancing will total $2922 million.

It is expected that approximately $3,1083 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 $2024 ($101 million, for each of the two reactors owned by the Company with assessments not to exceed $105 million per reactor per year) currently in force.

Notes:

1 Dominion Resources 2004 Annual Report page 25 - Plant construction and other property additions 2Dominion Resources 2004 Annual Report page 25 - Debt repayments net of issuances 3 Dominion Resources, Inc 2005 estimated internal cash flow - certified 4Dominion Resources 2004 Annual Report page 88 - Insurance ($101 x 2 = $202 million) 5 Dominion Resources 2004 Annual Report page 88 - Insurance $10 million

SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One)

E- 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 D 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 1-8489 DOMINION RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Virginia 54-1229715 (State or other jurisdiction (I.R.S. Employer or incorporation or organization) Identification No.)

120 Tredegar Street Richmond, Virginia 23219 (Address of principal executive ofices) (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 Which Registered Common stock, no par value New York Stock Exchange 8.75% Equity income securities, $50 par New York Stock Exchange 8.4% Trust preferred securities, $25 par New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act:

None Indicate by check mark whether the registrant (l) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes E 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 III of this Form 10-K or any amendment to this Form 10-K. E Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).

Yes 23 No LI The aggregate market value of the common stock held by non-affiliates of the registrant was approximately $20.8 billion based on the closing price of Dominion's common stock as reported on the New York Stock Exchange as of the last day of the registrant's most recently completed second fiscal quarter.

As of February 1,2005, Dominion had 340,591,545 shares of common stock outstanding.

DOCUMENT INCORPORATED BY REFERENCE.

(a)Portions of the 2005 Proxy Statement are incorporated by reference in Part 111.

Dominion Resources, Inc.

Item Page Number Number Part I

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

2. Properties . .................................................................................. 11

3. Legal Proceedings .................................... I 14

4. Submission of Matters to a Vote of Security Holders ............................ 14 Executive Officers of the Registrant .................................................................... 15 Part 11

5. Market for the Registrant's Common Equity and Related Stockholder Matters ...... ................ . 16

6. Selected Financial Data ................. ........... . 1.

16

7. Management's Discussion and Analysis of Financial Condition and Results of Operations .. 17 7A. Quantitative and Qualitative Disclosures About Market Risk ..................................... 46

8. Financial Statements and Supplementary Data ......................... ............. 47

9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ............. ........... 93 9A. Controls and Procedures ............................................................ 93 9B. Other Information ..................... ......................... 93 Part III

10. Directors and Executive Officers of the Registrant ................. ........................................ 94

11. Executive Compensation ...........................................  : ... 9.....................

94 12., Security Ownership of Certain Beneficial Owners and Management ........ .............. I ................ 94

13. Certain Relationships and Related Transactions ............................... ' 94

14. Principal Accountant Fees and Services ........................... ....... 94 Part IV

15. Exhibits and Financial Statement Schedules .............................. ............................ 95

Part 1 Item 1. Business Dominion Delivery The Company Dominion Delivery includes Dominion's electric and gas distribution systems and customer service operations as well as retail energy Dominion Resources, Inc. (Dominion) isa fully integrated gas and electric marketing operations. Electric distribution operations serve residential, holding company headquartered inRichmond, Virginia. Incorporated in commercial, industrial and governmental customers inVirginia and Virginia in1963, Dominion isa registered public utility holding company northeastern North Carolina. Gas distribution operations serve resi-under the Public Utility Holding Company Act of 1935 (the 1935 Act).

dential, commercial and industrial gas sales and transportation Dominion concentrates its efforts largely inwhat Dominion refers to customers inOhio, Pennsylvania and West Virginia. Retail energy as the "MAIN to Maine" region. Inthe power industry, "MAIN" means marketing operations include the marketing 'of gas, electricity and the Mid-America Interconnected Network, which comprises all of Illinois related products and services to residential and small commercial and portions of the states of Missouri, Iowa, Wisconsin, Michigan and customers inthe Northeast, Mid-Atlantic and Midwest regions.

Minnesota. Under this strategy, Dominion focuses its efforts on the region stretching from MAIN, through its primary Mid-Atlantic service areas inOhio, Pennsylvania, West Virginia, Virginia and North Carolina, Competition and up through New York and New England. The MAIN-to-Maine region Within Dominion's certificated service territory inVirginia and ishome to approximately 40% of the nation's demand for energy. North Carolina, there is no competition for electric distribution The term "Dominion' is used throughout this report and, service.

depending on the context of its use, may represent any of the Deregulation isat varying stages inthe three states inwhich Domin-following: the legal entity, Dominion Resources, Inc., one of ion's gas distribution subsidiaries operate. InPennsylvania, supplier Dominion Resources, Inc.'s consolidated subsidiaries or the entirety choice is available for all residential and small commercial customers. In of Dominion Resources, Inc. and its consolidated subsidiaries. Ohio, legislation has not been enacted to require supplier choice for Dominion's principal direct legal subsidiaries are Virginia Electric residential and commercial natural gas consumers. However, Dominion and Power Company (Virginia Power), Consolidated Natural Gas offers an Energy Choice program to customers on its own initiative, in Company (CNGI and Dominion Energy, Inc. (DEI). Virginia Power isa cooperation with the Public Utilities Commission of Ohio (Ohio regulated public utility that generates, transmits and distributes power Commission). West Virginia does not require customer choice inits retail for sale inVirginia and northeastern North Carolina. CNG operates in natural gas markets at this time. See Regulation-State Regulations for all phases of the natural gas business, explores for and produces gas additional information.

and oil and provides a variety of energy marketing services. CNG is also a transporter, distributor and retail marketer of natural gas, serving customers inPennsylvania, Ohio, West Virginia and other Regulation states. CNG also operates a liquefied natural gas (LNG) import and Dominion Delivery's electric retail service, including the rates it storage facility in Maryland. DEI is involved inmerchant generation, may charge to customers, is subject to regulation by the Virginia energy trading and marketing and natural gas and oil exploration and State Corporation Commission (Virginia Commission) and the North production. Carolina Utilities Commission (North Carolina Commission). See As of December 31, 2004, Dominion and its subsidiaries had approx- Regulation-State Regulations-Electric for additional information.

imately 16,500 full-time employees. Approximately 6,000 employees are Dominion Delivery's gas distribution service, including rates subject to collective bargaining agreements. The contracts of employees that it may charge customers, is regulated by the Ohio Commis-represented by the Utility Workers' Union of America, United Gas sion, the Pennsylvania Public Utility Commission (Pennsylvania Workers' Local 69-Il, AFL-CIO (Local 69-11) expire April 1,2005. Dominion Commission) and the West Virginia Public Service Commission and Local 69-11 have begun negotiations for new contracts. (West Virginia Commission). See Regulation-State Regulations-Dominion's principal executive offices are located at 120 Tredegar Gasfor additional information.

Street, Richmond, Virginia 23219 and its telephone number is (804) 819-2000.

Properties Operating Segments Dominion Delivery's electric distribution network includes approx-imately 54,000 miles of distribution lines, exclusive of service level Dominion manages its operations through four primary business lines, inVirginia and North Carolina. The right-of-way grants for lines that integrate its electric and gas services, streamline oper- most electric lines have been obtained from the apparent owner of ations and position it for long-term growth inthe competitive real estate, but underlying titles have not been examined except marketplace: Dominion Delivery, Dominion Energy, Dominion for transmission lines of 69 kV or more. Where rights-of-way have Exploration & Production and Dominion Generation. Dominion also not been obtained, they could be acquired from private owners by reports Corporate and Other functions as a segment. While condemnation, if necessary. Many electric lines are on publicly Dominion manages its daily operations as described below, its owned property, where permission to operate can be revoked.

assets remain wholly-owned by its legal subsidiaries. For additional financial information on business segments and geographic areas, see Note 27 to the Consolidated Financial Statements.

D 2004 1 Page 1

Dominion Delivery's investment in its gas distribution network electric transmission business competes with other electric transmission is located inthe states of Ohio, Pennsylvania and West Virginia. providers, primarily on the basis of rates and availability of service.

The gas distribution network involves approximately 27,000 miles Dominion Energy's gas transmission operations compete with of pipe, exclusive of service pipe, and 203 billion cubic feet Jbcf) of domestic and Canadian pipeline companies and gas marketers underground gas storage capacity inOhio, Pennsylvania and West seeking to provide or arrange transportation, storage and other Virginia. See Dominion Energy-Properties for additional services for customers. Alternative energy sources, such as oil or information regarding Dominion Delivery's storage properties. coal, provide another level of competition. Although competition is based primarily on price, the array of services that can be provided to customers isalso an important factor. The combination of Sources of Fuel Supply capacity rights held on certain longline pipelines, a large storage Dominion Delivery's supply of electricity to serve its retail capability and the availability of numerous receipt and delivery customers is primarily provided by Dominion Generation. See points along its own pipeline system enables Dominion to tailor its Dominion Generation for additional information. services to meet the needs of individual customers.

Dominion Delivery isengaged inthe sale and storage of natural gas through its operating subsidiaries. Dominion Delivery's gas supply is obtained from various sources including: purchases from major and Regulation independent producers inthe Mid-Continent and Gulf Coast regions; Dominion Energy's electric transmission operations are subject to purchases from local producers inthe Appalachian area; purchases from regulation by the Federal Energy Regulatory Commission (FERC),

gas marketers: and withdrawals from Dominion's and third party under- the Virginia Commission and the North Carolina Commission. FERC ground storage fields. also regulates Dominion's natural gas pipeline transmission, storage and LNG operations. See State Regulations and Federal Regulations inRegulation for additional information.

Seasonality Dominion Delivery's business typically varies seasonally based on Properties demand for electricity by residential and commercial customers for Dominion Energy has approximately 6,000 miles of electric trans-cooling and heating use based on changes intemperature. The same mission lines located inthe states of North Carolina, Virginia and is true for gas sales based on heating needs.

West Virginia. Portions of Dominion Energy's electric transmission lines cross national parks and forests under permits entitling the Dominion Energy federal government to use, at specified charges, surplus capacity Dominion Energy includes the following operations: inthe line, if any exists.

• A regulated interstate gas transmission pipeline and storage Dominion maintains major electric transmission interconnections system, serving Dominion's gas distribution businesses and with Progress Energy, American Electric Power Company, Inc., PJM-other customers in the Midwest, the Mid-Atlantic states and West and PJM. Through this major transmission network, Dominion the Northeast; has arrangements with these entities for coordinated planning,

• A regulated electric transmission system principally located in operation. emergency assistance and exchanges of capacity and Virginia and northeastern North Carolina; energy. See also Regional Transmission Organization (RTO) inFuture

• An LNG import and storage facility inMaryland; Issues and Other Matters in Item 7. Management's Discussion and

• Certain gas production operations located inthe Appalachian Analysis of Financial Condition and Results of Operations (MD&A).

basin; and Dominion Energy has approximately 7,900 miles of gas transmission,

• Clearinghouse, which is responsible for energy trading, gathering and storage pipelines located inthe states of Maryland, New marketing, hedging, arbitrage, and gas aggregation activities. York, Ohio, Pennsylvania, Virginia and West Virginia, Dominion's storage operations involve both the Dominion Delivery During the fourth quarter of 2004, Dominion performed an evalua-and Dominion Energy segments. Storage operations include 26 under-tion of its Clearinghouse trading and marketing operations, which ground gas storage fields located inNew York, Ohio, Pennsylvania and resulted ina decision to exit certain energy trading activities and West Virginia, with more than 2,000 storage wells and approximately instead focus on the optimization of company assets. Beginning in 372,000 acres of operated leaseholds. Dominion Energy and Dominion 2005, all revenues and expenses from the Clearinghouse's opti-Delivery together have more than 100 compressor stations with approx-mization of company assets will be reported as part of the results of imately 626,000 installed compressor horsepower. The total designed the business segments operating the related assets, inorder to capacity of the underground storage fields isapproximately 965 bcf of better reflect the performance of the underlying assets. As a result which 203 bcf isoperated by Dominion Delivery and 762 bcf isoperated of these changes, 2004 and 2003 results now reflect revenues and by Dominion Energy. Six of the 26 storage fields are jointly-owned with expenses associated with coal and emissions trading and marketing other companies and have a capacity of 243 bcf. Dominion Energy also activities inthe Dominion Generation segment.

has approximately 8 bcf of above ground storage capacity at its Cove Point LNG facility.

Competition The map below illustrates Dominion's gas transmission pipelines, Dominion Energys electric transmission business isnot subject to storage facilities, ING facility and electric transmission lines.

competition for transmission service to loads served within its Virginia and North Carolina service territories. Inconnection with transmission service to loads outside of its electric service territory, Dominion's D 2004/ Page 2

Dominion Energy's Gas Transmissi D and Storage/ Electric Transmission Lines

-;, r+ , s 1 a ~_Lii',.i 11 He 2r

-Natural Gas Transmission Pipelines

--- Natural GasTransmission Pipelines (Partnership)

_ Natural Gas Underground Storage Pools

.Electric Transmission Lines (Bulk delivery)

A Cove Point LNG Facility Sources of Energy Supply Competition Dominion's large underground natural gas storage network and the Dominion Exploration & Production's competitors range from location of its pipeline system are a significant link between the coun- major, international oil companies to smaller, independent pro-try's major gas pipelines and large markets inthe Northeast and Mid- ducers. Dominion Exploration & Production faces significant Atlantic regions and on the East Coast Dominion's pipelines are part of competition inthe bidding for federal offshore leases and in an interconnected gas transmission system, which continues to provide obtaining leases and drilling rights for onshore properties. Since local distribution companies, marketers, power generators and industrial and commercial customers accessibility to supplies nationwide. Dominion Exploration & Production is the operator of a number of Dominion's underground storage facilities play an important properties, it also faces competition insecuring drilling equipment part in balancing gas supply with consumer demand and are and supplies for exploration and development.

essential to serving the Midwest, Mid-Atlantic and Northeast Interms of its production activities, Dominion Exploration &

regions. In addition, storage capacity isan important element in Production sells most of its deliverable natural gas and oil into short the effective management of both gas supply and pipeline trans- and intermediate-term markets. Dominion Exploration & Production port capacity. faces challenges related to the marketing of its natural gas and oil production due to the contraction of participants inthe energy marketing industry. However, Dominion Exploration & Production Seasonality owns a large and diverse natural gas and oil portfolio and maintains Dominion Energy's business isaffected by seasonal changes inthe an active gas and oil marketing presence inits primary production prices of commodities that it actively markets and trades. regions, which strengthens its knowledge of the marketplace and delivery options.

Dominion Exploration & Production Dominion Exploration & Production includes Dominion's gas and oil Regulation exploration, development and production operations. These oper- Dominion's exploration and production operations are subject to ations are located inseveral major producing basins in the lower' regulation by numerous federal and state authorities. The pipeline 48 states, including the outer continental shelf and deepwater transportation of Dominion's natural gas production isregulated by areas of the Gulf of Mexico, and Western Canada. FERC and pipelines operating on or across the Outer Continental Shelf are subject to the Outer Continental Shelf Lands D2004/Page3

Act, which requires open-access, non-discriminatory pipeline facili- Properties ties. Dominion's production operations in the Gulf of Mexico and Dominion Exploration & Production owns 5.9 trillion cubic feet of most of its operations in the western United States are located on proved equivalent natural gas reserves and produces approx-federal oil and gas leases administered by the Minerals Manage-imately 1.2 billion cubic feet of equivalent natural gas per day from ment Service (MMS) or the Bureau of Land Management. These its leasehold acreage and facility investments. Dominion, either leases are issued through a competitive bidding process and alone or with partners, holds interests innatural gas and oil lease-require Dominion's compliance with stringent regulations. Offshore acreage, wellbores, well facilities, production platforms and production facilities must comply with MMS regulations relating to gathering systems. Dominion also owns or holds rights to seismic engineering, construction and operational specifications and the data and other tools used inexploration and development drilling plugging and abandonment of wells. Dominion's production oper-activities. Dominion's share of developed leasehold totals ations are also subject to numerous environmental regulations 3.0 million acres, with another 2.2 million acres held for future including regulations relating to oil spills into navigable waters of exploration and development drilling opportunities. See also the United States. See Regulation-Federal Regulations and Item 2.Properties for additional information on Dominion Explora-Regulation-Environmental Regulation for additional information.

tion & Production's properties.

Dominion Exploration & Production (Major Operating Areas)

• 100 We.

I Note: Includes the activities of the Dominion Exploration & Production segment andthe production activity of Dominion Transmission, Inc.. which isincluded the Dominion Energy segment Bcfe billion cubic feet equivalent 5

Mmcre = million cubic feet equivalent Seasonality generation mix isdiversified and includes coal, nuclear, gas, oil, hydro and purchased power. Dominion's strategy for its electric Dominion Exploration & Production's business can be affected by generation operations focuses on serving customers inthe MAIN-to seasonal changes in the demand for natural gas and oil.

Maine-region. Its generation facilities are located inVirginia, West Commodity prices, including prices for unhedged Dominion natural Virginia, North Carolina, Connecticut, Illinois, Indiana, Pennsylvania gas and oil production, can be affected by seasonal weather and Ohio. Inaddition, Dominion completed the acquisition of three changes and weather effects.

USGen New England Inc. (USGen) power stations located inMassa-chusetts and Rhode Island during January 2005 and expects to Dominion Generation complete the acquisition of the Kewaunee nuclear power plant Dominion Generation includes more than 28,000 Mw of generation located in northeastern Wisconsin during the first half of 2005. In capability for Dominion's electric utility and merchant fleet The addition, as discussed above, as a result of the reorganization of the D 2004 /Page 4

Clearinghouse, Dominion Generation's 2004 and 2003 results now Sources ofFuelSupply.

reflect revenues and expenses associated with coal and emissions Dominion Generation uses a variety of fuels to power its electric trading and marketing activities by the Clearinghouse that were generation. These include a mix of both nuclear fuel and fossil fuel previously reported in the Dominion Energy segment. as described further below.

Nuclear Fuel-Dominion Generation utilizes primarily long-term Competition contracts to support its nuclear fuel requirements. Worldwide For Dominion Generation's electric utility subsidiary, retail choice market conditions are continuously evaluated to ensure a range of has been available for all of Dominion's Virginia electric customers supply options at reasonable prices. Current agreements, inventories since January 1,2003; however, to date, competition inVirginia and spot market availability are expected to support current and has not developed to the extent originally anticipated. See Regu- planned fuel supply needs. Additional fuel ispurchased as required lation-State Regulations- Currently, North Carolina does not offer to ensure optimum cost and inventory levels. .

retail choice to electric customers. Fossil Fuel-Dominion Generation utilizes coal, oil and natural gas in Dominion Generation's merchant generation fleet owns and oper- its fossil fuel operations. Dominion Generation's coal supply is ates three large facilities inthe Midwest. These generating plants are obtained through long-term contracts and spot purchases. Oil-fired all under long-term contracts and are therefore largely unaffected by generation are used primarily to support heavier system generation competition. loads during very cold or very hot weather periods. Additional utility The majority of Dominion Generation's remaining merchant assets requirements are purchased mainly under short-term spot agree-operates within functioning Independent System Operators (ISO). ments.

Competitors include other generating assets bidding to operate within Dominion Generation uses natural gas as needed throughout the ISOs. These ISOs have clearly identified market rules that ensure the year for Dominion's utility and merchant generation facilities.

the competitive wholesale market isfunctioning properly. Dominion Dominion's gas supply is obtained from various sources including:

Generation's merchant units have a variety of short and medium term purchases from major and independent producers inthe Mid-contracts, and also compete inthe spot market with other generators continent and Gulf Coast regions; purchases from local producers to sell any number of products including energy, capacity and inthe Appalachian area; purchases from gas marketers; and with-operating reserves. It isdifficult to compare various types of gen- drawals from Dominion's and third party underground storage eration given the wide range of fuels, fuel procurement strategies, fields.

efficiencies, and operating characteristics of the fleet within any given Firm natural gas transportation contracts (capacity) exist that ISO. However, management believes that Dominion has the expertise allow delivery of gas to Dominion Generation's facilities. Dominion inoperations, dispatch and risk management to maximize the degree Generation's capacity portfolio allows flexible natural gas deliv-eries to its gas turbine fleet, while minimizing costs.

to which its merchant fleet iscompetitive compared to like assets within the region.

Seasonality Regulation Dominion Generation's sales of electricity typically vary season-InVirginia and North Carolina, Dominion's electric utility generation ally based on demand fcr electricity by residential and commercial customers for cooling and heating use based on changes in facilities, along with power purchases, are used to serve its utility temperature.

service area obligations. Due to 2004 deregulation legislation, rev-enues for serving Virginia jurisdictional retail load are based on capped rates through 2010 and the related fuel costs for the generating fleet Nuclear Decommissioning including power purchases, are subject to a fixed rate recovery through Dominion Generation has a total of six licensed, operating nuclear July 1.2007 when a one-time prospective adjustment will be consid- reactors at its Surry and North Anna plants inVirginia and its ered. During this transition period, the risk of fuel factor-related cost Millstone plant in Connecticut. Surry and North Anna serve recovery shortfalls may adversely impact Dominion's cost structure. customers of Dominion's regulated electric utility operations.

Conversely, Dominion may experience a positive economic impact to Millstone is a nonregulated merchant plant with two operating the extent that it can reduce its fuel factor-related costs. Subject to units. A third Millstone unit ceased operations before Dominion market conditions, any generation remaining after meeting utility acquired the plant.

system needs is sold outside of Dominion's service area. See Regu- Decommissioning represents the decontamination and removal lation-State Regulations and Regulation-Federal Regulations- of radioactive contaminants from a nuclear power plant once oper-Environmental Regulation for additional information. ations have ceased, inaccordance with standards established by the NRC. Amounts collected from ratepayers and placed intrusts are Properties being invested to fund future costs of decommissioning the Surry and North Anna units. As part of its acquisition of Millstone, For a listing of Dominion Generation's generation facilities, see Dominion acquired the decommissioning trusts for the three units Item 2. Properties.

that were fully funded to the regulatory minimum as of the acquis-ition date. Currently, Dominion believes that the amounts available inthe trusts and their expected earnings will be sufficient to cover D 2004/ Page 5

expected decommissioning costs for the Millstone units, without any performed. Millstone Unit I will be monitored until decommissioning additional contributions to the trusts. activities begin for the remaining Millstone units. The current operating The total estimated cost to decommission Dominion's seven nuclear licenses expire inthe years detailed inthe following table. During 2003, units is$3.0 billion based upon site-specific studies completed in2002. the NRC approved Dominion's application for a 20-year life extension for Dominion expects to perform new cost studies in2006. For all units the Surry and North Anna units and Dominion has filed a similar request except Millstone Unit 1 and Unit 2,the current cost estimates assume for the Millstone units in2004. Dominion expects to decommission the decommissioning activities will begin shortly after cessation of oper- Surry and North Anna units during the period 2032 to 2045 and the ations, which will occur when operating licenses expire. Millstone Unit 1 Millstone units during the period 2034 to 2057.

isnot inservice and selected minor decommissioning activities are being Surry North Anna Millstone Unit I Unit 2 Unit I Unit 2 Unit 1 Unit 2 Unit 3 Total (millions)

NRC license expiration year 2032 2033 2038 2040 2015 2025 Current cost estimate (2002 dollars)- $375 $368 $391 $363 $531 $486 $518 $3,032 Funds intrusts at December31, 2004 313 308 256 242 279 315 310 2,023 2004 contributions to trusts 1 11 7 7 - - - 36 I1)Unit 1 ceased operations in 1993 before Dominion's acquisition of Millstone.

Corporate and Other a long-term power purchase agreement and acquisition of the related generating facility used by Panda-Rosemary, LP, a non-Dominion also has a Corporate and Other segment that includes:

utility generator, to provide electricity to Dominion.

• Dominion's corporate, service company and other operations, See Kewaunee Power Plant, USGen Power Stations and including unallocated debt; Restructuring of Contract with Non-Utility Generatorin Future

• The remaining assets of Dominion Capital, Inc., (DCI) a financial Issues and OtherMatters in MD&A for additional information on services subsidiary, which are being divested inaccordance the above business developments.

with a Securities and Exchange Commission (SEC) order;

• The net impact of Dominion's discontinued telecommunications operations that were sold inMay 2004; and Regulation

• Specific items attributable to Dominion's operating segments Dominion issubject to regulation by the SEC, FERC, the Environ-that are reported inCorporate and Other. mental Protection Agency (EPA), the Department of Energy (DOE),

the Nuclear Regulatory Commission (NRC), the Army Corps of Engineers, and other federal, state and local authorities.

Business Developments InJanuary 2005, the Public Service Commission of Wisconsin State Regulations granted Dominion's request to rehear the case involving Domin- Electric ion's proposed purchase of the Kewaunee nuclear power plant, Dominion's electric retail service issubject to regulation by the located innortheastern Wisconsin. The commission had voted to Virginia Commission and the North Carolina Commission.

deny the sale in November 2004. During the fourth quarter of 2003, Dominion's electric utility subsidiary holds certificates of public Dominion reached an agreement to buy the Kewaunee nuclear convenience and necessity authorizing it to maintain and operate power plant from Wisconsin Public Service Corporation, a sub- its electric facilities now inoperation and to sell electricity to sidiary of WPS Resources Corporation (WPS), and Wisconsin customers. However, it may not construct or incur financial Power & Light Company (WP&L), a subsidiary of Alliant Energy commitments for construction of any substantial generating facili-Corporation for an aggregate purchase price of $220 million in ties or large capacity transmission lines without the prior approval cash, including $35 million for nuclear fuel. If approved by the of various state and federal government agencies.

commission, the transaction is expected to close in the first half of Status ofElectric Deregulation in Virginia 2005.

The Virginia Electric Utility Restructuring Act (Virginia InJanuary 2005, Dominion closed on its purchase of three Restructuring Act) was enacted in 1999 and established a plan to electric power generation facilities from USGen for $642 million.

restructure the electric utility industry inVirginia. The Virginia The acquisition was part of a bankruptcy court-approved divest-Restructuring Act addressed, among other things: capped base iture of generation assets by USGen. The plants include the 1,521-rates, RTO participation, retail choice, the recovery of stranded megawatt Brayton Point Station inSomerset, Massachusetts; the costs and the functional separation of a utility's electric generation 743-megawatt Salem Harbor Station in Salem, Massachusetts; from its electric transmission and distribution operations.

and the 426- megawatt Manchester Street Station inProvidence, Retail choice has been available to all of Dominion's Virginia Rhode Island.

regulated electric customers since January 1,2003. Dominion has In February 2005, Dominion paid $42 million in cash and also separated its generation, distribution and transmission assumed $62 million indebt inconnection with the termination of D 2004/ Page 6

functions through the creation of divisions within Virginia Power. The wires charge exemption program would allow large Codes of conduct ensure that Virginia Power's generation and industrial and commercial customers, as well as aggregated other divisions operate independently and prevent cross-subsidies customers in all rate classes, to avoid paying wires charges when between the generation and other divisions. selecting supply service from a competitive service provider by Since the passage of the Virginia Restructuring Act, the com- agreeing to market-based pricing upon return to the incumbent petitive environment has not developed inVirginia as anticipated. electric utility. Customers electing this option would waive the InApril 2004, the Governor of Virginia signed into law amend- right to return to capped rate service from the incumbent electric ments to the Virginia Restructuring Act and the Virginia fuel factor utility. The program is limited to the first 1,000 Mw of load or eight statute. The amendments extend capped base rates to December percent of the utility's prior year Virginia adjusted peak load inthe 31, 2010, unless modified or terminated earlier under the Virginia first 18 months of the program.

Restructuring Act. In addition to extending capped rates, the inJanuary 2005, Dominion filed compliance plans and the amendments: required market-based pricing methodology for both programs. To

• Lock in Dominion's fuel factor provisions until the earlier of July encourage a successful program and the development of retail 1,2007 or the termination of capped rates; competition, Dominion has proposed that customers that enroll

• Provide for a one-time adjustment of Dominion's fuel factor, with a competitive service provider inthe wires charge exemption effective July 1,2007 through December 31, 2010 (unless program in2005 be allowed to return to service with Dominion at capped rates are terminated earlier under the Virginia capped rates after October 2007 instead of market-based pricing.

Restructuring Act), with no adjustment for previously incurred The Virginia Commission must approve these proposals prior to over-recovery or under-recovery, thus eliminating deferred fuel implementation.

accounting for the Virginia jurisdiction; and In December 2004, Dominion filed its annual market prices/

• End wires charges on the earlier of July 1,2007 or the wires charges compliance plan with the Virginia Commission.

termination of capped rates, consistent with the Virginia Calculation of the 2005 wires charges inaccordance with the Restructuring Act's original timetable. formula approved by the Virginia Commission produced zero wires The risk of fuel factor-related cost recovery shortfalls may charges for 2005 for all but a few smaller rate classes. As a result, adversely impact its cost structure during the transition period and Dominion voluntarily agreed to forego the collection of any wires Dominion could realize the negative economic impact of any such. charges during 2005. Dominion's decision to forego wires charges adverse event. Conversely, Dominion may experience a positive in2005 is not intended to set a precedent for subsequent periods.

economic impact to the extent that it can reduce its fuel factor- Dominion intends to collect wires charges infuture periods should related costs for its electric utility generation-related operations. the Virginia Commission-approved methodology determine that Dominion anticipates that its unhedged natural gas and oil wires charges are applicable.

production will act as a natural internal hedge for natural gas and See Regulation-Federal Regulations-Federal Energy Regu-oil fuel costs associated with electric generation. If natural gas latory Commission and Status of Electric Deregulation in Virginia in and oil prices rise, it is expected that Dominion's exploration and Future Issues and Other Matters inMD&A for additional production operations will earn greater profits that will offset information on capped base rates, stranded costs and RTO partic-higher fuel costs and lower profits inDominion's electric gen- ipation.

eration operations. Conversely, if gas and oil prices fall, it is RetailAccess Pilot Programs expected that Dominion's electric generation operations will incur The three retail access pilot programs, approved by the Virginia-lower fuel costs and earn higher profits that will offset lower Commission in'2003, continue to be available to customers. These profits inDominion's exploration and production operations .

programs are to run through the remainder of the capped rate Dominion also anticipates that the fixed fuel rate will lessen the period and will make available to competitive service providers up impact of seasonally mild weather on its electric generation oper-to 500 megawatts of load, with potential participation of more ations. During periods of mild weather it isexpected that electric than 65,000 customers from a variety of customer classes.

generation operations will burn less high-cost fuel because customers will use less electricity, thereby offsetting decreased Rate Matters revenues. Alternatively, in periods of extreme weather, Dominion's Virginia-ln December 2003, the Virginia Commission approved higher fuel costs from running costlier plants are expected to be Dominion's proposed settlement of its 2004 fuel factor increase of mitigated by additional revenue as customers use more electricity. $386 million. The settlement includes a recovery period for the Other amendments to the Virginia Restructuring Act were also under-recovery balance over three and a half years. Approximately enacted with respect to a minimum stay exemption program, a $171 million of the $386 million was recovered in2004 with $85 wires charge exemption program and allowing the development of million to be recovered in2005, $87 million in 2006 and $43 million a coal-fired generating plant in southwest Virginia for serving in the first six months of 2007.

default service needs. Under the minimum stay exemption pro- As a result of amendments to the Virginia Restructuring Act in gram, large customers with a load of 500 kW or greater would be 2004, Dominion's capped based rates were extended to December exempt from the twelve month minimum stay obligation under 31, 2010. Inaddition, Dominion's fuel factor provisions were frozen capped rates if they return to supply service from the incumbent until July 1,2007, after which they can be only adjusted once more utility at market-based pricing after they have switched to supply through December 31, 2010. See Status of Electric Deregulation in service with a competitive service provider. Virginia above for additional information regarding the Virginia Restructuring Act amendments.

D 2004/ Page 7

North Carolina-In connection with the North Carolina regulatory assets. The purchased gas cost recovery filings gen-Commission's approval of the CNG acquisition, Dominion agreed erally cover prospective one, three or twelve-month periods.

not to request an increase inNorth Carolina retail electric base Approved increases or decreases in gas cost recovery rates result rates before 2006, except for certain events that would have a in increases or decreases in revenues with corresponding significant financial impact on Dominion's electric utility oper- increases or decreases in net purchased gas cost expenses.

ations. Fuel rates are still subject to change under the annual fuel Ohio-In December 2003, the Ohio Commission approved a cost adjustment proceedings. However inApril 2004, the North joint application filed by Dominion and several other Ohio natural Carolina Commission commenced an investigation into Dominion's gas companies for recovery of bad debt expense via a rider known North Carolina base rates and subsequently ordered Dominion to as a bad debt tracker. The tracker insulates Dominion from the file a general rate case to show cause why its North Carolina base effect of changes in bad debt expense, which is affected by the rates should not be reduced. The rate case was filed in September volatility of natural gas prices, weather and prices charged by 2004 and inFebruary 2005, Dominion reached a tentative settle- competitive retail natural gas suppliers. The tracker is an adjust-ment with parties inthe case that is subject to North Carolina able rate that recovers the cost of bad debt ina manner similar to Commission approval before becoming effective. a gas cost recovery rate. Instead of recovering bad debt costs through its base rates, Dominion recovers all eligible bad debt Gas expenses through the bad debt tracker and removes bad debt from Dominion's gas distribution service is regulated by the Ohio base rates. Annually, Dominion assesses the need to adjust the Commission, the Pennsylvania Commission and the West Virginia tracker based on the preceding year's actual bad debt expense.

Commission.

Pennsylvania-In July 2004, the Pennsylvania Commission Status of Gas Deregulation approve a settlement agreement between Dominion and the Office Each of the three states inwhich Dominion has gas distribution of Consumer Advocate (OCA) inwhich the OCA agreed to drop its operations has enacted or considered legislation regarding dereg- appeal of a previous Pennsylvania Commission order that allowed ulation of natural gas sales at the retail level. Dominion to recover approximately $16.5 million inunrecovered Ohio-Ohio has not enacted legislation requiring supplier choice purchased gas costs. As part of the settlement, all customer for residential and commercial natural gas consumers. However, in service and delivery charges will be fixed through December 31, cooperation with the Ohio Commission, Dominion on its own ini- 2008. Gas costs will continue to pass through to the customer tiative offers retail choice to customers. At December 31, 2004, through the purchased gas cost adjustment mechanism.

approximately 548,000 of Dominion's 1.2 million Ohio customers Federal Regulations were participating inthis open-access program. Large industrial Public Utility Holding Company Act of 1935 customers inOhio also source their own natural gas supplies.

Dominion is a registered holding company under the 1935 Act. The Pennsylvania-In Pennsylvania, supplier choice is available for 1935 Act and related regulations issued by the SEC govern activ-all residential and small commercial customers. At December 31, ities of Dominion and its subsidiaries with respect to the issuance 2004, approximately 88,000 residential and small commercial and acquisition of securities, acquisition and sale of utility assets.

customers had opted for Energy Choice inDominion's Pennsylvania certain transactions among affiliates, engaging in businesses service area. Nearly all Pennsylvania industrial and large commer-activities not directly related to the utility or energy business and cial customers buy natural gas from nonregulated suppliers.

other matters.

West Virginia-At this time, West Virginia has not enacted Dominion became a registered public utility holding company legislation to require customer choice inits retail natural gas when it completed the CNG acquisition inJanuary 2000. The 1935 markets. However, the West Virginia Commission has issued Act prohibits registered companies from owning businesses not regulations to govern pooling services, one of the tools that natural directly related to utility or other energy operations. Dominion has gas suppliers may utilize to provide retail customer choice in the substantially completed its exit of the core operating businesses of future and has issued rules requiring competitive gas service DCI, its financial services subsidiary, and continues to seek oppor-providers to be licensed inWest Virginia.

tunities to divest the remaining assets. Currently, Dominion is Rate Matters-Gas Distribution required to divest of all remaining DCI holdings by January 2006.

Dominion's gas distribution business subsidiaries are subject to Federal Energy Regulatory Commission regulation of rates and other aspects of their businesses by the Electric states in which they operate-Pennsylvania, Ohio and West Virginia. When necessary, Dominion's gas distribution subsidiaries Under the Federal Power Act, FERC regulates wholesale sales of electricity and transmission of electricity in interstate commerce by seek general rate increases on a timely basis to recover increased public utilities. Dominion's electric utility subsidiary sells elec-operating costs. In addition to general rate increases, certain of tricity inthe wholesale market under its market-based sales tariff Dominion's gas distribution subsidiaries make routine separate authorized by FERC but does not make wholesale power sales filings with their respective state regulatory commissions to reflect under this tariff to loads located within its service territory. In changes in the costs of purchased gas. These purchased gas costs addition, Dominion's electric utility subsidiary has FERC approval are generally subject to rate recovery through a mechanism that of a tariff to sell wholesale power at capped rates based on its ensures dollar for dollar recovery of prudently incurred costs. Costs embedded cost of generation. This cost-based sales tariff could be that are expected to be recovered in future rates are deferred as used to sell to loads within or outside its service territory. Any D 2004 l Page 8

- y¶."I-such sales would be voluntary. Dominion's sales of natural gas, struction and operation of natural gas import facilities and inter-liquid hydrocarbon by-products and oil inwhole~sle markets are state natural gas pipeline facilities.

not regulated by FERC. FERC Order 636 requires transmission pipelines to operate as The Virginia Restructuring Act requires that Dominion join an*1 , open-access transporters and provide transportation and storage RTO, and FERC encourages RTO formation as ameans to foster services on an equal basis for all gas suppliers, whether purchased wholesale market formation. Dominion and PJM Interconnection,. from Dominionor from another gas supplier.

LLC (PJM) entered into an agreemeit inSeptember 2002 that Dominion's interstate gas transportation and storage activities provides that, subject to regulatory approval and certain provi- are conducted in accordance with certificates, tariffs and service sions, Dominion will become a member of PJM arid transfer func-. agreements on file with FERC..

tional control of its electric transmission facilities to PJM for Dominion isalso subject to the Pipeline Safety Act of 2002, inclusion ina new PJM South Region. InOctober 2004, FERC which includes new mandates regarding the inspectiorn frequency issued an order conditionally approving Dominion's application to for interstate and intrastate natural gas transmission and storage join PJM. and inNovember 2004, the Virginia Commission pipelines located inareas of high-density population where the approved Dominion's application to join PJM subject to certain,. consequences of potential pipeline accidents pose the greatest .

terms and conditions. The North Carolina Commission evidentiary risk to people and their property". Dominion has evaluated its hearing was held inJanuary 2005. Dominion cannot predict the natural gas transmission and storage properties under the final outcome of this matter at this time. regulations issued inDecember 2003 and has developed the Ina separate order issued inSeptember 2004. FERC granted required implementation plan including identification, testing and authority to Dominion subsidiaries with market based rate potential remediation activities.

authority to charge market based rates for sales of electric energy Dominion implemented various rate filings, tariff changes and and capacity to loads located within the Company's service terri- negotiated rate service agreements for its FERC-regulated busi-tory upon its integration into PJM. For additional information, see. nesses during 2004. Inall material respects, these filings were RTO inFuture Issues and OtherMatters in MD&A. - . . approved by FERC in the form requested by Dorminion and were Dominion isalso subject to FERC's Standards of Conduct that. subject to only minor modifications.

govern conduct between interstate transmission gas and electricity Environmental Regulations

providers and their marketing function or their energy related, Each operating segment faces substantial regulation and corn-'

affiliates. The rule defines the scope of the affiliates covered by, pliance costs with respect to environmental matters. For a dis-the standards and isdesigned to prevent transmission providers cussion of significant aspects of these matters, including current from giving their marketing functions or affiliates undue and planned capital expenditures relating to environmental com-preferences. pliance, see Environmental Matters inFuture Issues and Other InJune 2004. FERC approved Dominion's filing to provide Matters inMD&A. Additional information can also be found in optional backup supply service to competitive service providers Item 3.Legal Proceedings and Note 22 to the Cdnsolidated Finan-serving retail customers, including the retail pilot programs, in cial Statements; Dominion's service territory inVirginia. The filing addressed From time to time Dominion may be identified as a potentially competitive service providers' concerns with the availability of responsible party to a Superfund site. The EPA (or a state) can transmission capacity to move energy into Virginia. The backup either (a)allow such a party to conduct and pay for a remedial supply service will allow competitive service providers to continue' investigaiiori, feasibility study and remedial action or lb) conduct to serve their customers in Dominion's service area inVirginia the remedial investigation and action and then seek reimburse-during periods of supply interruption. This is an interim solutioni ment from'the parties. Each party can be held joiritly, severally and until Dominion isintegrated into PJM. '

• strictly liable for all costs. These parties can also bring contribution a s6ttlement'of InAugust 2004. Dominion and FERC announced actions against each other and seek reimbursement from their a self-reported infraction of FERC regulations involving data'- insurance companies. As aresult, Dominion may be responsible for sharing of non-public gas storage information. Under the settle- the costs of remedial investigation and actions under the Super-ment, Dominion paid a$500,000 civil penalty and refunded $4.5 fund Act or other laws or regulations regarding the remediation of million to its non-affiliated natural gas storage customers. Inaddi- waste. Dominion does not believe that any currently identified tion, Dominion agreed to enhance internal training and oversight of. sites will result in significant liabilities.

employees who handle non-public, market-sensitive data. InJanuary 2004. the EPA proposed additional regulations Gas addressing pollution transport from electric generating plants as FERC regulates the transportation and sale'for resale of natural well as the regulation of mercury and nickel emissions. These gas in interstate commerce under the Natural Gas Act of 1938 and regulatory actions, inaddition to revised regulations to address the Natural Gas Policy Act of 1978, as amended. Under the Natural regional haze, are expected to be finalized in2005 and could Gas Act, FERC has authority over rates, terms and conditions of require additional reductions inemissions from the Company's services performed by Dominion's interstate gas pipeline sub- fossil fuel-fired generating facilities. Ifthese new emission reduc-sidiaries, including Dominion Transmission, Inc. (DTI) and Dominion tion requirements are imposed, additional significant expenditures Cove Point LNG, [P. FERC also has jurisdiction over siting, con- may be required.

D 2004I/Page 9

In March 2004, the State of North Carolina filed a petition From time to time, the NRC adopts new requirements for the under Section 126 of the Clean Air Act seeking the EPA to impose operation and maintenance of nuclear facilities. In many cases, additional nitrogen oxide (NOx) and sulfur dioxide (SO 2) reductions these new regulations require changes inthe design, operation from electrical generating units inthirteen states, claiming emis- and maintenance of existing nuclear facilities. If the NRC adopts sions from the electrical generating units in those states are con- such requirements in the future, it could result in substantial tributing to air quality problems in North Carolina. Dominion has increases inthe cost of operating and maintaining Dominion's electrical generating units in six of the states. The issues raised by. nuclear generating units.

North Carolina are already being addressed by the EPA in current The NRC also requires Dominion to decontaminate nuclear regulatory initiatives. The EPA is expected to respond to the peti- facilities once operations cease. This process is referred to as tion in2005. Given the highly uncertain outcome and timing of decommissioning, and Dominion is required by the NRC to be future action, if any, by the EPA on this issue, Dominion cannot financially prepared. For information on Dominion's predict the financial impact, if any, on its operations at this time. decommissioning trusts, see Dominion Generation-Nuclear The United States Congress isconsidering various legislative Decommissioningand Note 11 to the Consolidated Financial proposals that would require generating facilities to comply with Statements.

more stringent air emissions standards. Emission reduction requirements under consideration would be phased inunder a Where You Can Find More Information About Dominion variety of periods of up to 15 years. If these new proposals are Dominion files its annual, quarterly and current reports, proxy adopted, additional significant expenditures may be required. statements and other information with the SEC. Dominion's SEC InJuly 2004, the EPA published new regulations that govern filings are available to the public over the Internet at the SEC's existing utilities that employ a cooling water intake structure, and web site at http://www.sec.gov. You may also read and copy any whose flow levels exceed a minimum threshold. The EPA's rule document Dominion files at the SEC's public reference room at presents several compliance options. Dominion is evaluating 450 Fifth Street, NW, Washington, D.C. 20549. Please call the SEC information from certain of its existing power stations and expects at 1-800-SEC-0330 for further information on the public reference to spend approximately $16 million over the next 5 years room.

conducting studies and technical evaluations. Dominion cannot Dominion's website address is www.dom.com. Dominion predict the outcome of the EPA regulatory process or state with makes available, free of charge through its website, its annual any certainty what specific controls may be required. : report on Form 10-K, quarterly reports on Form 10-0, current Dominion has applied for or obtained the necessary environ- reports on Fbirm 8-K and any amendments to those reports as soon mental permits for the operation of its regulated facilities. Many of as practicable after filing or furnishing the material with the SEC.

these permits are subject to re-issuance and continuing review. You may also request a copy of these filings, at no cost, by writing or telephoning us at: Corporate Secretary, Dominion, 120 Tredegar Nuclear Regulatory Commission Street, Richmond, Virginia 23219, Telephone (804) 819-2000.

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

D 2004/ Page 10

Item 2. Properties Substantially all of Dominion's electric utility's property is subject to the lien of the mortgage securing its First and Refunding Dominion leases its principal executive office inRichmond, Virginia Mortgage Bonds and certain of Dominion's nonutility generation as well as corporate offices in other cities inwhich its subsidiaries facilities are subject to liens.

operate. It also owns two corporate offices inRichmond.

Information detailing Dominion's gas and oil operations pre-Dominion's assets consist primarily of its investments inits sented below and on the following page includes the activities of subsidiaries, the principal properties of which are described below the Dominion Exploration & Production segment and the pro-and in Item 1.Business.

duction activity of Dominion Transmission, Inc.(DTI), which is included inthe Dominion Energy segment:

Company-Owned Proved Gas and Oil Reserves Estimated net quantities of proved gas and oil reserves at December 31 of each of the last three years were as follows:

2004 2003 2002 Proved Total Proved . .. Total Proved , Total Developed Proved Developed Proved Developed Proved Proved gas reserves (bcf)

United States 3,680 4,904 3,553 4.801 3,549 4,458 Canada 96 99 453 568 486 640 Total proved gas reserves 3,776 5,003 4,006 5,369 4,035 5,098 Proved oil reserves (000 bbl)

United States 87,382 128,924 42,347 135,914 47,759 138,798 Canada 11,459 19,674 17,407 34,020 18,064 30,432 Total proved oil reserves 98,841 148,598 59,754 169,934 65,823 .169,230 Total proved gas and oil reserves lbcfe) . 4,369 5,894 4,364 6,388 4,430 6,113 Certain subsidiaries of Dominion file Form EIA-23 with the DOE, reserves associated with the Company-owned proved reserves which reports gross proved reserves, including the working inter- reported inthe table above, does not exceed five percent. Esti-ests share of other owners, for properties operated by such mated proved reserves as of December 31, 2004 are based upon Dominion subsidiaries. The proved reserves reported inthe table studies for each Dominion property prepared by Dominion's staff above represent Dominion's share of proved reserves for all engineers and reviewed by either Ralph E.Davis Associates, Inc. or properties, based on Dominion's ownership interest ineach prop- Ryder Scott Company, L.P. Calculations were prepared using erty. For properties operated by Dominion, the difference between standard geological and engineering methods generally accepted the proved reserves reported on Form EIA-23 and the gross by the petroleum industry and inaccordance with SEC guidelines.

Quantities of Gas and Oil Produced Quantities of gas and oil produced during each of the last three years ending December 31 follow:

2004 2003 2002 Gas production lbcf)

United States 327 346 346 Canada 44 50 53 Total gas production 371 396 399 Oil production 1000 bblsl United States 8,800 7,642 8,653 Canada 1,201 1,081 1,072 Total oil production 10.001 6,723 9,725 Total gas and oil production lbcfe) 431 449 458 The average sales price per thousand cubic feet (mcf] of gas with hedging results (including transfers to other Dominion operations at market prices) realized during the years 2004, 2003 and 2002 was $4.14, $3.98 and $3.41, respectively. The respective average prices without hedging results per mcf of gas produced were $5.66, $5.02 and $3.04. The respective average sales prices realized for oil with hedging results were $24.99, $24.30 and $23.29 per barrel and the respective average prices without hedging results were $39.06. $29.82 and $24.45 per barrel. The average production (lifting) cost per mcf equivalent of gas and oil produced (as calculated per SEC guidelines) during the years 2004, 2003 and 2002 was $0.91, $0.80 and $0.60, respectively.

D 2004I/Page 11

Acreage Gross and net developed and undeveloped acreage at December 31, 2004 was:

Undeveloped Developed Acreage Acreage Gross Net Gross Net (thousands)

United States 4,223 2,559 3.208 1,766 Canada 731 471 577 483 Total 4,954 3.030 3.785 2,249 Net Wells Drilled in the Calendar Year The number of net wells completed during each of the last three years ending December 31 follows:

2004 2003 2002 Exploratory:

United States Productive 7 8 12 Dry 7 7 12 Total United States 14 15 24 Canada Productive 34 10 1 Dry 7 1 . 1 Total Canada 41 11 2 Total Exploratory 55 26 26 Development:

United States Productive 921 819 774 Dry 17 36 38 Total United States 938 855 812 Canada Productive 36 31 61 Dry 3 10 11 Total Canada 39 41 72 Total Development 977 896 884 Total wells drilled Inet): 1,032 922 910 As of December 31, 2004, 133 gross (92 net) wells were inprocess of being drilled, including wells temporarily suspended.

Productive Wells The number of productive gas and oil wells inwhich Dominion's subsidiaries had an interest at December 31, 2004, follows:

Gross Net Gas wells United States 24.698 16,457 Canada 644 408 Total gas wells 25.342 16,865 Oil wells United States 1.004 517 Canada 426 163 Total oil wells 1.430 680 The number of productive wells includes 297 gross (117 net) multiple completion gas wells and 29 gross (12 net) multiple completion oil wells. Wells with multiple completions are counted only once for productive well count purposes.

Dominion's Power Generation Dominion Generation provides electricity for use on a wholesale and a retail level. Dominion Generation can supply electricity demand either from its generation facilities inConnecticut, Indiana, Illinois, Massachusetts, North Carolina, Ohio, Pennsylvania, Rhode Island, Virginia and West Virginia or through purchased power contracts when needed. The following table lists Dominion's generating units and capability, including the generating plants acquired from USGen effective January 1,2005.

0 2004 /Page 1Z

Dominion's Power Generation Primary Fuel Net Summer Plant Location Type Capability (Mw)

Utility Generation North Anna Mineral, VA Nuclear 1,62B1a)

Surry Surry. VA Nuclear 1,598 Mt. Storm -Mt. Storm, WV Coal 1,569 Chesterfield Chester, VA Coal 1.234 Chesapeake Chesapeake, VA Coal 595 Clover Clover, VA Coal 4411b)

Yorktown Yorktown, VA Coal 325 Brerno 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 . umfries, VA _ol..786 Gravel Neck (CT) Sorry, VA oil 183 Darbytown (CT) Richmond. VA oil 144 Chesapeake (CT) Chesapeake, VA Oil .144 Possum Point (CT) Dumfries, VA oil 78 Northern Neck (CT) Lively. VA Oil 64 Low Moor (CT) -Covington. VA oil 60 Kitty Hawk (CT) Kitty Hawk, NC Oil 44 Remington (CT) Remington. VA Gas 580 Possum Point (CC) Dumfries, VA Gas 545f 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 Da rbytown (CT) Richmond, VA Gas 144 Bath County Warm Springs, VA Hydro 1,477(d)

Gaston Roanoke Rapids. NC Hyd ra 225 Roanoke Rapids Roanoke Rapids. NC Hydra 99 Pittsylvania Hurt. VA Other 80 Other Various Various 15 15.356(e)

Non-utility Generation Millstone Waterford, CT. Nuclear 1,953(f)

Kincaid Kincaid, IL Coal 1.158 Brayton Point Somerset, MA Coal 1,078(g)

State Line Hammond, IN Coal 515 Salem Harbor Salem. MA Coal 312(gl Morgantown Morgantown, 'WV Coal 25(h1 Brayton Point Somerset. MA Oil 435(g)

Salem Harbor Salem. MA Oil 431 (g)

Fairless (CC) -Fairless Hills. PA Gas 1.096(c)

Elwood (CT) Elwood. IL Gas 704i)

Armstrong (CT) Shelocla, PA Gas 625(c)

Tray (CT) Luckey, OH Gas 600(c)

Manchester (CC) Providence, RI Gas 426(g)

Plea sants (CT) St. Mary's. WV Gas 3131c)

Other Various Various 38 9,709.

Purchased Capacity 3,081 (I)

Total Capacity 28,146 Note: (CT) denotes combined cycle denotes combustion turbine and (CC)

(a)Excludes 11.6 percent undivided interest owned by Old Dominion Electric Cooperative (00DEC).

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

(chIncludes generating units which Dominion operates under leasing arrangements.

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

(e)Totals may not add due to rounding.

(I]Excludes 6.53 percent undivided interest inUnit 3owned by Massachusetts Municipal Wholesale Electric Company and Central Vermont Public Service Company.

(g)Acqtuired January 1.2005 from UISGen New England. Inc. The Brayton Point Station also has four small generation units fired by oil-diesel (combined capacity 8Mwv) included inNon-Utility Generation-Other.

(h)Excludes 50 percent partnership interest owned by Cogen Technologies Morgantown, Ltd. and Hickory Power Corporation.

Ii)Excludes 50 percent partnership interest owned by Peoples Energy.

(j)Purchase capacity includes generation from the Batesville facility. Dominion has decided to divest its interest inthe long-term power tolling contract associated with this facility. See Long-Tern Power Tolting Contract inMD&A for additional information.

D 20041 Page 13

Item 3.Legal Proceedings InApril 1998, Harrold E.(Gene) Wright, an oil and gas' entrepreneur, brought suit against Dominion Exploration & Pro-From time to time, Dominion and its subsidiaries are alleged to be duction, Inc. (formerly known as CNG Producing Company), a inviolation or indefault under orders, statutes, rules or regulations subsidiary of CNG, alleging various fraudulent valuation practices relating to the environment, compliance plans imposed upon or inthe payment of royalties on federal leases. Shortly after filing, agreed to by Dominion and its subsidiaries, or permits issued by this case was consolidated under the Federal Multidistrict Liti-various local, state and federal agencies for the construction or gation rules with the Grynberg case noted above. A substantial operation of facilities. Administrative proceedings may also be portion of the claim against CNG Producing Company was resolved pending on these matters. Inaddition, inthe ordinary course of by settlement in late 2002. The case was remanded back to the business, Dominion and its subsidiaries are involved invarious U.S. District Court for the Eastern District of Texas, which denied legal proceedings. Management believes that the ultimate reso-the defendant's motion to dismiss on jurisdictional grounds in lution of these proceedings will not have a material adverse effect January 2005. Discovery may begin inthe matter inthe spring of on Dominion's financial position, liquidity or results of operations.

2005.

See Regulation in Item 1.Business, Future Issues and Other InAugust 2004, DTI received a proposed Consent Order and Matters inMD&A, and Note 22 to the Consolidated Financial Agreement (COA) from the Pennsylvania Department of Environ-Statements for additional information on rate matters and various mental Protection (PADEP) which would supersede a 1990 COA regulatory proceedings to which Dominion is a party.

between the parties. The proposed COA would resolve ground-Before being acquired by Dominion, Louis Dreyfus Natural Gas water contamination issues at several DTI compressor stations in Corp. (Louis Dreyfus) was one of numerous defendants in3 lawsuit Pennsylvania. The draft COA proposes penalties to be paid to consolidated and now pending in the 93rd Judicial District Court in PADEP and the Pennsylvania Department of Conservation and Hidalgo County, Texas. The lawsuit alleges that gas wells and Natural Resources to resolve alleged violations. The proposed COA related pipeline facilities operated by Louis Dreyfus, and other has not been accepted by OTI and issubject to ongoing negotia-facilities operated by other defendants, caused an underground tions with the agencies. Management believes that the ultimate hydrocarbon plume in McAllen, Texas. The plaintiffs claim that resolution of the COA will not have a material effect on Dominion.

they have suffered damages, including property damage and lost profits, as a result of the alleged plume and seek compensation for these items.

InJuly 1997, Jack Grynberg, an oil and gas entrepreneur, Item 4.Submission of Matters to a Vote of brought suit against CNG and several of its subsidiaries. The suit Security Holders seeks damages for alleged fraudulent mismeasurement of gas None.

volumes and underreporting of gas royalties from gas production taken from federal leases. The suit was consolidated with approx-imately 360 other cases inthe U.S. District Court for the District of Wyoming. Parts of Mr. Grynberg's claims were dismissed on the basis that they overlapped with Mr. Wright's claims, which are noted below. Mr. Grynberg has filed an appeal. The defendants have filed a motion to dismiss.

D 2004/ Page 14

Executive Officers of the Registrant Name and Age 'Business Experience Past Five Years Thos. E. Capps (69) Chairman of the Board of Directors and Chief Executive Officer of Dominion from August 2000 to date; Chairman of the Board of Directors of Virginia Electric and Power Company from September 1997 to date; Chairman of the Board of Direc-tors 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; Chairman of the Board of Directors, President and Chief Executive Officer of Dominion from September 1995 to January 2000.

Thomas F. Farrell, 11(50) President and Chief Operating Officer of Dominion from January 2004 to date; President and Chief Operating Officer of Consolidated Natural Gas Company from January 2004 to date; Executive Vice President of Dominion from March 1999 to December 2003; President and Chief Executive Officer of Virginia Electric and Power Company from December,2002 to December 2003; Executive Vice President of Consolidated Natural Gas Company from January 2000 to December 2003; Chief Executive Officer of Virginia Electric and Power Company from May 1999 to December 2002.

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

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.

Duane C.Radtke (561 Executive Vice President of Dominion and Consolidated Natural Gas Company from April 2001 to date; President of Devon Energy International from August 2000 to April 2001; Executive Vice President-Production of Santa Fe Snyder Corp. from May 1999 to August 2000.

Mary C. Doswell (46) Senior Vice President and Chief Administrative Officer of Dominion from January 2003 to date; President and Chief Executive Officer of Dominion Resources Services. Inc. from January 2004 to date; President of Dominion Resources Services, Inc. from January 2003 to December 2003; Vice President-Billing and Credit of Virginia Electric and Power Company from October 2001 to December 2002; Vice President-Metering of Virginia Electric and Power Company from January 2000 to October 2001.

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 Presi-dent-Portfolio Management of Virginia Electric and Power Company from January 2000 to December 2002.

Mark F. McGettrick (47) President and Chief Executive Officer-Generation of Virginia Electric and Power Company from January 2003 to date; Senior Vice President and Chief Administrative Officer of Dominion from January 2002 to December 2002; President of Dominion Resources Services, Inc. from October 2002 to January 2003; Senior Vice President-Customer Service and Metering of Virginia Electric and Power Company from January 2000 to December 2001.

Eva S. Hardy (60) Senior Vice President-External Affairs &Corporate Communications of Dominion from May 1999 to date; Senior Vice President-External Affairs & Corporate Communications of Virginia Electric and Power Company from September 1997 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.

James L. Sanderlin (63) Senior Vice President-Law of Dominion from September 1999 to date; Senior Vice President-Law of Consolidated Natural Gas Company from January 2000 to date.

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 Virginia Electric and Power Company, Consolidated Natural Gas Company, Dominion Resources Services, Inc. and Dominion Energy, Inc. reflects service at a subsidiary of Dominion.

In May 2004, Dominion sold its telecommunications subsidiary, Dominion Telecom, Inc., to a third party and Dominion Telecom, Inc.

became Elantic Telecom, Inc. Subsequent to the sale, Elantic Telecom, Inc. filed for protection under Chapter 11 of the U.S. Federal Bank-ruptcy code. Messrs. Johnson and Hetzer served as executive officers of Dominion Telecom, Inc. during the two years prior to its sale.

D 2004/Page 15

Part 11 Item 5.Market for the Registrant's During 2004, Dominion issued 111 shares of common stock to a former employee as a deferred payment under a 1985 performance Common Equity and Related Stockholder achievement plan. These shares were not registered under the Matters Securities Act of 1933 (Securities Act). The issuance of this stock Dominion's common stock is listed on the New York Stock did not involve a public offering, and istherefore exempt from Exchange. At December 31. 2004, there were approximately registration under the Securities Act.

170,000 registered shareholders, including approximately 79,000 The following table presents registered shares tendered by certificate holders. The quarterly information concerning stock employees to satisfy tax withholding obligations on vested prices and dividends is in orporated by reference from Note 29 to restricted stock during the fourth quarter of 2004.

the Consolidated Financial Statements. Restrictions on the pay-ment of dividends by Dominion are discussed in Note 20 to the Consolidated Financial Statements.

Issuer Purchases of Equity Securities (a) NbI (c) (d)

Total Average Total Number Maximum Number (or Number of Price of Shares (orUnits) Approximate Dollar Value)

Shares Paid per Purchased as Part of Shares (orUnits) that May (or Units) Share of Publicly Announced Yet BePurchased under the Period . Purchased iI) (orUnit) Plans orPrograms Plans or Program 10/1/04- 10/31/04 - - N/A N/A 11/1/04 -11/30/04 - - N/A N/A 12/1/04- 12/31/04 84 $66.41 N/A N/A Total 84 $66.41 N/A N/A (1)Amounts are registered shares tendered by employees to satisfy tax withholding obligations on vested restricted stock.

Item 6. Selected Financial Data 20)4t 200321 2002 2001t13 200(4t (millions, except per share amounts)

Operating revenue $13,972 $12,078 $10,218 $10,558 $ 9,246 Income from continuing operations before cumulative effect of changes in accounting principles 1,264 949 1,362 544 415 5

Loss from discontinued operations, net of taxes( 1 115) 16421 - -

Cumulative effect of changes inaccounting principles, net of taxes - 11 - - 21 Net income 1.249 318 1.362 544 436 Income from continuing operations before cumulative effect of changes in accounting principles per common share-basic 3.84 2.99 4.85 2.17 1.76 Net income per common share-basic 3.8$0 1.00 4.85 2.17 1.85 Income from continuing operations before cumulative effect of changes in accounting principles per common share-diluted 3.82 2.93 4.82 2.15 1.76 Net income per common share-diluted 3.78 1.00 4.82 2.15 1.85 Dividends paid per share Z60 2.58 2.58 2.58 2.58 Total assets 45.446 43,546 39,239 36,044 30,449 Long-term debts' 15,507 15,776 12,060 12,119 10,101 Preferred securities ofsubsidiary trusts' - - 1,397 1,132 385 (1)Dominion's 2004 results include a $112 million after-tax charge reflecting 141Dominion's 2000 results include $198 million of after-tax restructuring and other Dominion's valuation of its interest in a long-term power tolling contract and $61 acquisition-related costs resulting from the merger with Consolidated Natural Gas million of after-tax losses related to the discontinuance of hedge accounting for Company.

certain oil hedges, resulting from an interruption of oil production inthe Gulf of (51Reflects the net impact of Dominion's discontinued telecommunications oper-Mexico caused by Hurricane Ivan, and subsequent changes in the fair value of ations that were sold in May 2004. See Note 9 to the Consolidated Financial those hedges. Statements.

121 Dominion's 2003 results include $122 million of after-tax incremental restoration (61Upon adoption of Financial Accounting Standards Board Interpretation No. 46 expenses associated with Hurricane Isabel. Also in2003, Dominion adopted (revised December 2003), Consolidation of Variable Interest Entities, on accounting standards that resulted inthe recognition of the cumulative effect of December 31,2003 with respect to special purpose entities, Dominion began changes inaccounting principles. See Note 3to the Consolidated Financial State- reporting as long-term debt its junior subordinated notes held by five capital ments. trusts, rather than the trust preferred securities issued by those trusts. See Note 13)Dominion's 2001 results include a $97 million after-tax charge representing 3 to the Consolidated Financial Statements.

exposure to the Enron Corp. bankrupcty and $68 million of after-tax charges associated with a senior management restructuring initiative.

D 20041 Page 16

Item 7.Management's Discussion and its efforts largely inwhat Dominion refers to as the "MAIN to Maine" region. Inthe power industry, MAIN" means the Mid-America Inter-Analysis of Financial Condition and connected Network, which comprises all of Illinois and portions of the Results of Operations states of Missouri, Iowa, Wisconsin, Michigan and Minnesota. Under Management's Discussion and Analysis of Financial Condition and this strategy, Dominion focuses its efforts on the region stretching Results of Operations (MD&A) discusses the results of operations from MAIN, through its primary Mid-Atlantic service areas inOhio, and general financial condition of Dominion. MD&A should be read Pennsylvania, West Virginia, Virginia and North Carolina, and up inconjunction with the Consolidated Financial Statements. The through New York and New England. The MAIN-to-Maine region is term 'Dominion' is used throughout MD&A and, depending on the home to approximately 40% of the nation's demand for energy.

context of its use. may represent any of the following: the legal Operating inall aspects of the energy supply-chain allows entity, Dominion Resources, Inc.; one of Dominion Resources, Inc.'s Dominion to optimize the value of its energy portfolio and enhance consolidated subsidiaries; or the entirety of Dominion Resources, its return on invested capital. Dominion has the capability to discover Inc. and its consolidated subsidiaries. and produce gas, store it, sell it or use it to generate power; it can generate electricity to sell to customers in its retail markets or in Contents of MD&A wholesale transactions. These capabilities give Dominion the ability to produce and sell energy inwhatever form it finds most useful and The reader will find the following information in this MD&A:

economic. Dominion also operates North America's largest natural

• Forward-Looking'Statements gas storage system, which gives it the flexibility to provide supply

• Introduction when it is most economically advantageous to do so.

• Accounting Matters Dominion's businesses are managed through four primary

• Results of Operations operating segments: Dominion Generation, Dominion Energy,

• Segment Results of Operations Dominion Delivery and Dominion Exploration & Production. The

• Selected Information-Energy Trading Activities contributions to net income by Dominion's primary operating

• Sources and Uses of Cash segments are determined based on a measure of profit that execu-

• Future Issues and Other Matters tive management believes represents the segments' core earnings.

• Market Rate Sensitive Instruments and Risk Management As a result, certain specific items attributable to those segments

• Risk Factors and Cautionary Statements that May Affect Future are not included in profit measures evaluated by executive Results management in assessing segment performance or allocating resources among the segments. Those specific items are reported Forward-Looking Statements inthe Corporate and Other segment.

This report contains statements concerning Dominion's expect- Dominion Generation includes the generation operations of ations, plans, objectives, future financial performance and other Dominion's electric utility and merchant fleet. The generation mix is statements that are not historical facts. These statements are diversified and includes coal, nuclear, gas, oil, hydro and purchased

'forward-looking statements" within the meaning of the Private power. Dominion's strategy for its electric generation operations Securities Litigation Reform Act of 1995. Inmost cases, the reader focuses on serving customers inthe MAIN to Maine region. Its can identify these forward-looking statements by words such as generation facilities are located inVirginia, West Virginia, North "anticipate," "estimate," "forecast," "expect," 'believe," 'should," Carolina, Connecticut, Illinois, Indiana, Pennsylvania and Ohio. In "could," 'plan, "may" or other similar words. addition, Dominion completed the acquisition of three USGen New Dominion makes forward-looking statements with full knowledge England Inc. (USGen) power stations located in Massachusetts and that risks and uncertainties exist that may cause actual results-to Rhode Island during January 2005 and expects to complete the differ materially from predicted results. Factors that may cause acquisition of the Kewaunee nuclear power plant located innorth-actual results to differ are often presented with the forward-looking eastern Wisconsin inthe first half of 2005.

statements themselves. Additionally, other risks that may cause Utility generation operations represent Dominion Generation's actual results to differ fronm predicted results are set forth inRisk primary source of revenue and cash flow. These operations are Factorsand Cautionary Statements That MayAffectFuture Results. sensitive to external factors, primarily weather and fuel prices.

Dominion bases its forward-looking statements on management's Currently, revenue from utility operations largely reflects the beliefs and assumptions using information available at the time the capped rates charged to customers inVirginia, the majority of its statements are made. Dominion cautions the reader not to place utility customer base. Under Virginia's current deregulation legis-undue reliance on its forward-looking statements because the lation, electric rates are capped through 2010. Under capped rates, assumptions, beliefs, expectations and projections about future events changes in Dominion Generation's operating costs, particularly may, and often do, differ materially from actual results. Dominion with respect to fuel, relative to costs used to establish the capped undertakes no obligation to update any forward-looking statement to rates, will impact Dominion's earnings. Dominion Generation has reflect developments occurring after the statement ismade. reduced costs by terminating certain long-term power purchase agreements.

Introduction Dominion isa diversified, fully integrated electric and gas holding company headquartered inRichmond, Virginia. Dominion concentrates D 20041 Page 17

l il.

Prices received for electricity generated by its merchant fleet are a result of these changes, 2004 and 2003 results now reflect market-based, subjecting Dominion Generation to risks associated revenues and expenses associated with coal and emissions trading with recovering capital expenditures and absorbing'variability in and marketing activities inthe Dominion Generation segment.

fuel costs. Generally, Dominion Generation manages these risks by DominionDelivery includes Dominion's electric and gas dis-entering into both short-term and long-term fixed-price sales and tribution systems and customer service operations as well as retail purchase contracts. energy marketing operations. Electric distribution operations serve Variability in expenses for Dominion Generation relates residential, commercial, industrial and governmental customers in primarily to the cost of fuel consumed, labor and benefits and the Virginia and northeastern North Carolina. Gas distribution oper-timing, duration and costs of scheduled and unscheduled outages. ations serve residential, commercial and industrial gas sales and As discussed infurther detail below, as a result of the reorganiza- transportation customers inOhio, Pennsylvania and West Virginia.

tion of the Dominion Energy Clearinghouse (Clearinghouse), Retail energy marketing operations include the marketing of gas, Dominion Generation's 2004 and 2003 results now reflect revenues electricity and related products and services to residential and and expenses associated with coal and emissions trading and small commercial customers in the Northeast, Mid-Atlantic and marketing activities performed by the Clearinghouse that were Midwest.

previously reported inthe Dominion Energy segment. Revenue and cash flow provided by electric and gas distribution Dominion Energy includes the following operations: operations are based primarily on rates established by state regu-

• A regulated interstate gas transmission pipeline and storage latory authorities and state law. Variability inDominion Delivery's system, serving Dominion's gas distribution businesses and revenue and cash flow relates largely to changes in volumes, other customers inthe Midwest, the Mid-Atlantic states and which are primarily weather sensitive. For local gas distribution the Northeast; operations, revenue may vary based upon changes in levels of rate

• A regulated electric transmission system principally located in recovery for the cost of gas sold to customers: Such costs and Virginia and northeastern North Carolina; recoveries generally offset and do not materially impact net

• A liquefied natural gas (LNG) import and storage facility in income. Revenue from retail energy marketing operations may vary Maryland; inconnection with changes inweather and commodity prices as

• Certain gas production operations located inthe Appalachian well as the acquisition and potential loss of customers.

basin; and Variability inexpenses results from changes in the cost of

• Clearinghouse, which is responsible for energy trading, purchased gas and routine maintenance and repairs (including marketing, hedging, arbitrage and gas aggregation activities. labor and benefits as well as decisions regarding the use of Dominion Energy's revenue and cash flows are derived from resources for operations and maintenance or capital-related both regulated and nonregulated operations. activities). For gas distribution operations, Dominion ispermitted Revenue and cash flow provided by regulated electric and gas to seek recovery of the cost of gas sold to customers.

transmission operations and the LNG facility are based primarily on Dominion Exploration & Production includes Dominion's rates established by the Federal Energy Regulatory Commission gas and oil exploration, development and production operations.

(FERC). Variability inrevenue and cash flow provided by these busi- These operations are located in several major producing basins in nesses results primarily from changes inrates and the demand for the lower 48 states, including the outer continental shelf and services. Variability inexpenses relates largely to operating and deepwater areas of the Gulf of Mexico, and Western Canada.

maintenance expenditures, including decisions regarding use of Dominion Exploration & Production maintains an active and resources for operations and maintenance or capital-related activities. ongoing drilling program focused on low risk development drilling Revenue and cash flow for Dominion Energy's nonregulated in several proven onshore regions of the United States and businesses are subject to variability associated with changes in Western Canada, while also maintaining some exposure to higher commodity prices. Dominion Energy's nonregulated businesses use risk exploration opportunities. Significant development drilling .

physical and financial arrangements to hedge this price risk. Certain programs are currently underway inWest Texas, the Appalachians hedging and trading activities may require cash deposits to satisfy and the Rocky Mountains where Dominion Exploration & Pro-margin requirements. Inaddition, reported earnings for this segment duction holds sizable acreage positions and operational experi-reflect changes inthe fair value of certain derivatives; these values ence. While each region provides Dominion Exploration &

may change significantly from period to period. Variability in Production with exploration opportunities, most exploratory drilling expenses for these nonregulated businesses relates largely to labor takes place inthe Gulf Coast region, including the deepwater Gulf and benefits and the costs of purchased commodities for resale and of Mexico.

payments under financially-settled contracts.

During the fourth quarter of 2004, Dominion performed an evaluation of its Clearinghouse trading and marketing operations, which resulted ina decision to exit certain energy trading activities and instead focus on the optimization of company assets. Begin-ning in2005, all revenues and expenses from the Clearinghouse's optimization of company assets will be reported as part of the results of the business segments operating the related assets, in order to better reflect the performance of the underlying assets. As D 2004 /Page 18

Revenue and cash flow provided by exploration and production near-term future price information and use of statistical methods.

operations are based primarily on the production and sale of For options and contracts with option-like characteristics where company-owned natural gas and oil reserves. Variability in pricing information is not available from external sources, Dominion Exploration & Production's revenue and cash flow Dominion generally uses a modified Black-Scholes Model that.

relates primarily to changes in commodity prices, which are market considers time value, the volatility of the underlying commodities based, and volumes, which are impacted by numerous factors and other relevant assumptions. Dominion uses other option including drilling success, timing of development projects, as well models when contracts involve different commodities or as external factors such as the storm-related damage caused by commodity locations and when contracts allow either the buyer or Hurricane Ivan. Dominion manages commodity price volatility by seller the ability to exercise within a range of quantities. For con-hedging a substantial portion of its near term expected production. tracts with unique characteristics, Dominion estimates fair value Variability in Dominion Exploration & Production's expenses using a discounted cash flow approach., If pricing information is not relates primarily to changes inoperating costs and production available from external sources, judgment is required to develop taxes, which tend to increase or decrease with changes ingas and estimates of fair value. For individual contracts, the use of oil prices and the prevailing cost environment. Commodity price different valuation models or assumptions could have a material changes place upward or downward pressure on related explora- effect on the contract's estimated fair value..

tion and production service industry costs, while severance and For cash flow hedges of forecasted transactions, Dominion property taxes vary based on changes in revenue. A changing price must estimate the future cash flows represented by the forecasted environment impacts both operating costs and the cost of acquir- transactions, as well as evaluate the probability of occurrence and ing, finding and developing natural gas and oil reserves. timing of such transactions. Changes inconditions or the occur-Corporate and Other includes: rence of unforeseen events could require discontinuance of hedge

• Dominion's corporate, service company and other operations, accounting or could affect the timing for reclassification of gains or including unallocated debt; losses on cash flow hedges from accumulated other compre-

• The remaining assets of Dominion Capital, Inc. (DCI), a financial hensive income (loss) (AOCI) into earnings.

services subsidiary, which are being divested inaccordance Use of estimates in goodwillimpairment testing with a Securities and Exchange Commission (SEC) order; As of December 31, 2004, Dominion reported $4.3 billion of

• The net impact of Dominion's discontinued telecommunications goodwill on its Consolidated Balance Sheet, a significant portion operations that were sold inMay 2004; and of which resulted from the acquisition of CNG in2000. Sub-

• Specific items attributable to Dominion's operating segments stantially all of this goodwill is allocated to Dominion's Gen-that are reported in Corporate and Other.

eration, Transmission, Delivery and Exploration & Production Accounting Matters reporting units. InApril of each year, Dominion tests its goodwill for potential impairment, and performs additional tests more Critical Accounting Policies and Estimates frequently if impairment indicators are present. The 2004 annual Dominion has identified the following accounting policies, test did not result in the recognition of any impairment of goodwill, including certain inherent estimates, that as a result of the judg-as the estimated fair values of Dominion's reporting units ments, uncertainties, uniqueness and complexities of the under-exceeded their respective carrying amounts. During the fourth lying accounting standards and operations involved, could result in quarter of 2004, Dominion tested $72 million of goodwill allocated material changes to its financial condition or results of operations to the Clearinghouse reporting unit after management decided to under different conditions or using different assumptions.

exit certain energy trading activities and change the focus of the Management has discussed the development, selection and dis-business, which resulted ina reduction of the unit's expected closure of each of these with Dominion's Audit Committee.

future cash fows. This interim test indicated that no impairment Accountingfor derivative contractsat fair value existed and approximately $8million of the unit's goodwill was Dominion uses derivative contracts iprimarily forward purchases reallocated to other reporting units as of December 31, 2004 in and sales, swaps, options and futures) to buy and sell energy- connection with management's reorganization of that business. In related commodities and to manage its commodity and financial 2003 and 2002, impairment charges of $78 million and $13 million, markets risks. Derivative contracts, with certain exceptions, are respectively, were recognized as a result of interim tests con-subject to fair value accounting and are reported on the ducted for certain DCI subsidiaries and Dominion's tele-Consolidated Balance Sheets at fair value. Accounting communications business.

requirements for derivatives and related hedging activities are complex and may be subject to further clarification by standard-setting bodies.

Fair value of derivatives is based on actively quoted market prices, if available. Inthe absence of actively quoted market prices, Dominion seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, Dominion must estimate prices based on available historical and D 2004/Page 19

Dominion estimates the fair value of its reporting units by using a Asset retirement obligations combination of discounted cash flow analyses, based on its Dominion recognizes liabilities for the expected cost bf retiring tangible internal five-year strategic plan, and other valuation techniques long-lived assets for which a legal obligation exists. These asset retire-that use multiples of earnings for peer group companies and ment obligations (AROs) are recognized at fair value as incurred, and are analyses of recent business combinations involving peer group capitalized as part of the cost of the related tangible long-lived assets. In companies. These calculations are dependent on subjective factors the absence of quoted market prices, Dominion estimates the fair value such as management's estimate of future cash flows, the selection of its AROs using presentvalue techniques, inwhich Dominion makes of appropriate discount and growth rates, and the selection of peer various assumptions including estimates of the amounts and timing of group companies and recent transactions. These underlying future cash flows associated with retirement activities, credit-adjusted assumptions and estimates are made as of a point intime; sub- risk free rates and cost escalation rates. AROs currently reported on sequent modifications, particularly changes indiscount rates or Dominion's Consolidated Balance Sheets were measured during a growth-rates inherent inmanagement's estimates of future cash period of historically low interest rates. The impact on measurements of flows, could result ina future impairment of goodwill. Although new AROs, using different rates inthe future, may be significant Dominion has consistently applied the same methods in Dominion did not recognize any new, significant AROs in2004. Inthe developing the assumptions and estimates that underlie the fair future, if Dominion revises any assumptions used to calculate the fair value calculations, such as estimates of future cash flows, and value of existing AROs, Dominion will adjust the carrying amount of both based those estimates on relevant information available at the the ARO liability and related long-lived asset. Dominion records accretion time, such cash flow estimates are highly uncertain by nature and expense, increasing the ARO liability, with the passage of time. In2004 may vary significantly from actual results. If the estimates of future and 2003, Dominion recognized $91 million and $86 million, respectively, cash flows used in the 2004 annual test had been 10% lower, the ' of accretion expense, and expects to incur $95 million in2005.

resulting fair values would have still been greater than the carrying A significant portion of Dominion's AROs relate to the future values of each of those reporting units, indicating no impairment decommissioning of its nuclear facilities. At December 31, 2004, was present. nuclear decommissioning AROs, which are reported inthe Dominion Generation segment, totaled $1.4 billion, representing Use ofestimates in long-livedasset impairment testing approximately 82% of Dominion's total AROs. Based on their sig-Impairment testing for an individual or group of long-lived assets nificance, the following discussion of critical assumptions inherent or intangible assets with definite lives is required when circum- indetermining the fair value of AROs relates to those associated stances indicate those assets'may be impaired. When an asset's with Dominion's nuclear decommissioning obligations.

carrying amount exceeds the undiscounted estimated future cash Dominion obtains from third-party experts periodic site-specific flows associated with the asset, the asset is considered impaired "base year" cost studies in order to estimate the nature, cost and to the extent that the asset's fair value isless than its carrying timing of planned decommissioning activities for its utility nuclear amount. Performing an impairment test on long-lived assets plants. Dominion uses internal cost studies for its merchant involves management's judgment inareas such as identifying nuclear facility based on similar methods. These cost studies are circumstances indicating an impairment may exist, identifying and based on relevant information available at the time they are per-grouping affected assets and developing the undiscounted and formed; however, estimates of future cash flows for extended discounted estimated future cash flows (used to estimate fair periods are by nature highly uncertain and may vary significantly value inthe absence of market-based value) associated with the from actual results. In addition, these cost estimates are asset, including the selection of an appropriate discount rate. dependent on subjective factors, including the selection of cost Although cash flow estimates used by Dominion would be based escalation rates, which Dominion considers to be a critical on relevant information available at the time the estimates are assumption.

made, estimates of future cash flows are, by nature, highly Dominion determines cost escalation rates, which represent uncertain and may vary significantly from actual results. For projected cost increases over time, due to both general inflation example, estimates of future cash flows would contemplate fac- and increases inthe cost of specific decommissioning activities, tors such as the expected use of the asset, including future pro- for each of its nuclear facilities. The weighted average cost duction and sales levels, and expected fluctuations of prices of escalation used by Dominion was 3.18%. The use of alternative commodities sold and consumed. rates would have been material to the liabilities recognized. For During 2004, Dominion did not test any significant long-lived example, had Dominion increased the cost escalation rate by 0.5%

assets or asset groups for impairment as no circumstances arose to 3.68%, the amount recognized as of December 31, 2004 for its that indicated an impairment may exist. In2003, reflecting a sig- AROs related to nuclear decommissioning would have been $269 nificant revision in long-term expectations for potential growth in million higher.

telecommunications service revenue, Dominion approved a strategy to sell its interest inthe telecommunications business. In connection with this change instrategy, Dominion tested the network assets to be sold for impairment, using the revised long-term expectations for potential growth. Dominion's assets were determined to be substantially impaired and were written down to fair value. Dominion sold its telecommunications business in2004.

D 2004/Page 20

Employeebenefitplans actual cost trends experienced and projected, and demographics of Dominion sponsors noncontributory defined benefit pension plans plan participants. Dominion's medical cost trend rate assumption and other postretirement benefit plans for eligible active employ- as of December 31, 2004 is9%and is expected to gradually ees, retirees and qualifying dependents. The costs of providing decrease to 5%in later years.

benefits under these plans are dependent, inpart, on historical The following table illustrates the effect on cost of changing information such as employee demographics, the level of con- the critical actuarial assumptions discussed above, while holding tributions made to the plans and earnings on plan assets. Assump- all other assumptions constant:

tions about the future, including the expected rate of return on Increase inNet plan assets, discount rates applied to benefit obligations and the Periodic Cost anticipated rate of increase in health care costs and participant Other compensation, also have a significant impact on employee benefit Change in Pension Postretirement costs. The impact on pension and other postretirement benefit plan Actuarial Assumption Assumption Benefits Benefits obligations associated with changes inthese factors is generally (millions) recognized inthe Consolidated Statements of Income over the Discount rate (0.251% S 13 $6 remaining average service period of plan participants rather than Rate of return on plan assets (0.251% 10 2 immediately. Healthcare cost trend The selection of expected long-term rates of return on plan rate . 1% N/A 22 assets, discount rates and medical cost trend rates are critical assumptions. Dominion determines the expected long-term rates In addition to the effects on cost, a 0.25% decrease inthe of return on plan assets for pension plans and other postretirement discount rate would increase the projected pension benefit obliga-benefit plans by using a combination of: tion by $122 million and would increase the accumulated post-

• Historical return analysis to determine expected future risk retirement benefit obligation by $45 million.

premiums;

• Forward-looking return expectations derived from the yield on Accounting for regulated operations long-term bonds and the price earnings ratios of major stock Dominion's accounting for its regulated electric and gas operations market indices; differs from the accounting for nonregulated operations inthat

• Expected inflation and risk-free interest rate assumptions, and Dominion is required to reflect the effect of rate regulation in its

• Investment allocation of plan assets. Dominion's strategic Consolidated Financial Statements. Specifically, Dominion's regu-target asset allocation for its pension fund is45% U.S. equity lated businesses record assets and liabilities that nonregulated securities, 8%non-U.S. equity securities, 22% debt securities. companies would not report under accounting principles generally and 25% other, such as real estate and private equity accepted inthe United States of America. When it is probable that investments. regulators will allow for the recovery of current costs through future rates charged to customers, Dominion defers these costs Assisted by an independent actuary, management develops that otherwise would be expensed by nonregulated companies and assumptions, which are then compared to the forecasts of other recognizes regulatory assets inits financial statements. Likewise, independent investment advisors to ensure reasonableness. An Dominion recognizes regulatory liabilities inits financial state-internal committee selects the final assumptions. Dominion calcu-ments when it is probable that regulators will require reductions in lated its pension cost using an expected return on plan assets revenue associated with customer credits through future rates and assumption of 8.75% for 2004 and 2003, compared to 9.5% for when revenue iscollected from customers for expenditures that 2002. Dominion calculated its 2004 other postretirement benefit are not yet incurred.

cost using an expected return on plan assets assumption of7.79%,

Management evaluates whether or not recovery of its regu-compared to 7.78% and 7.82% for 2003 and 2002, respectively.

latory assets through future regulated rates is probable and makes The rate used incalculating other postretirement benefit cost is various assumptions in its analyses. The expectations of future lower than the rate used incalculating pension cost because of recovery are generally based on orders issued by regulatory differences inthe relative amounts of various types of investments commissions or historical experience, as well as discussions with held as plan assets and because other postretirement benefit applicable regulatory authorities. If recovery of regulatory assets is activity, unlike the pension activity, is partially taxable.

determined to be less than probable, the regulatory asset will be Discount rates are determined from analyses performed by a written off and an expense will be recorded inthe period such third party actuarial firm of AA/Aa rated bonds with cash flows assessment is made. Management currently believes the recovery matching the expected payments to be made under Dominion's of its regulatory assets is probable. See Notes 2 and 14 to the plans. Due to declines in bond yields and interest rates, Dominion Consolidated Financial Statements.

reduced the discount rate used to calculate 2004 pension and other postretirement benefit cost to 6.25% compared to the 6.75%

and 7.25% discount rates that it used to calculate 2003 and 2002 pension and other postretirement benefit cost, respectively.

The medical cost trend rate assumption isestablished based on analyses performed by a third party actuarial firm of various fac-tors including the specific provisions of Dominion's medical plans, D 2004/ Page 21

Accountingfor gas and oiloperations The accounting standards adopted during 2003 affect the com-Dominion follows the full cost method of accounting for gas and oil parability of Dominion's Consolidated Statements of Income. The exploration and production activities prescribed by the SEC. Under following discussion is presented to provide an understanding of the full cost method, all direct costs of property acquisition, the impacts of those standards on that comparability.

exploration and development activities are capitalized and sub-RN46R sequently depreciated using the units-of-production method. The The adoption of Financial Accounting Standards Board (FASB) depreciable base of costs includes estimated future costs to be Interpretation No. 46 (revised December 2003), Consolidation of incurred indeveloping proved gas and oil reserves, as well as Variable Interest Entities, (FIN 46R) on December 31, 2003 with capitalized asset retirement costs, net of projected salvage values.

respect to special purpose entities, affected the comparability of Capitalized costs inthe depreciable base are subject to a ceiling Dominion's 2004 Consolidated Statement of Income to prior years test prescribed by the SEC. The test limits capitalized amounts to a as follows:

ceiling-the present value of estimated future net revenues to be

• Dominion was required to consolidate certain variable interest derived from the production of proved gas and oil reserves lessor entities through which Dominion had financed and assuming period-end pricing adjusted for cash flow hedges in leased several new power generation projects, as well as its place. Dominion performs the ceiling test quarterly, on a country-corporate headquarters and aircraft. As a result, the by-country basis, and would recognize asset impairments to the Consolidated Balance Sheet as of December 31, 2003 reflects extent that total capitalized costs exceed the ceiling. In addition, an additional $644 million innet property, plant and equipment gains or losses on the sale or other disposition of gas and oil and deferred charges and $688 million of related debt. In2004, properties are not recognized, unless the gain or loss would sig-'

Dominion's Consolidated Statement of Income reflects nificantly alter the relationship between capitalized costs and depreciation expense on the net property, plant and equipment proved reserves of natural gas and oil attributable to a country.

and interest expense on the debt associated with these Dominion's estimate of proved reserves requires a large degree entities, whereas inprior years it reflected as rent expense in of judgment and is dependent on factors such as historical data, other operations and maintenance expense, the lease engineering estimates of proved reserve quantities, estimates of payments to these entities.

the amount and timing of future expenditures to develop the

• Inaddition, under FIN 46R, Dominion reports as long-term debt proved reserves, and estimates of future production from the its junior subordinated notes held by five capital trusts, rather proved reserves. Given the volatility of natural gas and oil prices, it than the trust preferred securities issued by those trusts. As a is possible that Dominion's estimate of discounted future net cash result, in 2004 Dominion reported interest expense on the flows from proved natural gas and oil reserves that is used to junior subordinated notes rather than preferred distribution calculate the ceiling could change inthe near term.

expense on the trust preferred securities.

The process to estimate reserves is imprecise, and estimates are subject to revision. In the last five years, revisions to Domin- SFAS No. 143 ion's estimates of proved developed and undeveloped reserves Adopting Statement of Financial Accounting Standards (SFAS) No.

have averaged approximately 3%of the previous year's estimate. 143, Accounting forAsset Retirement Obligations, on January 1, If there is a significant variance inany of its estimates or assump- 2003, affected the comparability of Dominion's 2004 and 2003 tions in the future and revisions to the value of its proved reserves Consolidated Statements of Income to the prior year as follows:

are necessary, related depletion expense and the calculation of the Accretion of the AROs, including nuclear decommissioning, is ceiling test would be affected and recognition of natural gas and reported inother operations and maintenance expense.

oil property impairments could occur. See Notes 2 and 28 to the Previously, expenses associated with the provision for nuclear Consolidated Financial Statements. decommissioning were reported indepreciation expense and in other income (loss); and Income Taxes

• Realized and unrealized earnings of trusts available for funding Judgment is required indeveloping Dominion's provision for decommissioning activities at Dominion's utility nuclear plants income taxes, including the determination of deferred tax assets are recorded inother income (loss) and AOCI, as appropriate.

and any related valuation allowance. Dominion evaluates the Previously, as permitted by regulatory authorities, these probability of realizing its deferred tax assets on a quarterly basis earnings, along with an offsetting charge to expense, for the by reviewing its forecast of future taxable income and the avail- accretion of the decommissioning liability, were both reported ability of tax planning strategies that can be implemented, if inother income (loss).

necessary, to realize deferred tax assets. Failure to achieve fore-casted taxable income or successfully implement tax planning strategies might affect the ultimate realization of deferred tax assets.

Newly Adopted Accounting Standards During 2004 and 2003, Dominion was required to adopt several new accounting standards, the requirements of which are dis-cussed in Notes 2 and 3 to the Consolidated Financial Statements.

D 2004/ Page 22

EITF02-3 and EITF03-11 marketing locations onshore. Dominion typically enters into either a The adoption of Emerging Issues Task Force (EITF) Issue No. 02-3, single or aseries of buy/sell transactions inwhich it sells its crude oil Issues Involved inAccounting for Derivative Contracts Held for production at the offshore field delivery point and buys similar quantities Trading Purposes and Contracts Involved in Energy Trading and at Cushing, Oklahoma for sale to third parties. Dominion isable to Risk Management Activities, and related EITF Issue No. 03-11, enhance profitability by selling to a wide array of refiners and/or trading Reporting Realized Gains and Losses on Derivative Instruments companies at Cushing, one of the largest crude oil markets inthe world, That Are Subject to FASO Statement No. 133 and Not 'Held for versus restricting sales to a limited number of refinery purchasers inthe Trading Purposes" as Defined inIssue No. 02-3, changed the Gulf of Mexico. These transactions require physical delivery of the crude timing of recognition inearnings for certain Clearinghouse energy- oil and the risks and rewards of ownership are evidenced by title trans-related contracts, as well as the financial statement presentation fer, assumption of environmental risk, transportation scheduling and of gains and losses associated with energy-related contracts. The counterparty nonperformance risk.

Consolidated Statement of Income for 2002 was not restated. Prior Under the primary guidance of EITF Issue No. 99-19, Reporting to 2003, all energy trading contracts, including non-derivative Revenue Gross as a Principal versus Net as an Agent, Dominion contracts, were recorded at fair value with changes infair value presents the sales and purchases related to its crude oil buy/sell and settlements reported inrevenue on a net basis. Specifically, arrangements on a gross basis inits Consolidated Statements of adopting EITF 02-3 and EITF 03-11 affected the comparability of . Income' The EITF is currently discussing Issue No.04-13, Accounting Dominion's 2004 and 2003 Consolidated Statements of Income to forPurchases and Sales of Inventory with the Same Counterparty, the prior year as follows: which specifically focuses on purchase and sale transactions made

• For derivative contracts not held for trading purposes that pursuant to crude oil buy/sell arrangements. The EITF isevaluating involve physical delivery of commodities, unrealized gains and whether these types of transactions should be presented net inthe losses and settlaments on sales contracts are presented in Consolidated Statements of Income. While resolution of this issue revenue, while unrealized gains and losses and settlements on may affect the income statement presentation of these revenues purchase contracts are reported in expenses; and and expenses, there would be no impact on Dominion's results of

• Non-derivative energy-related contracts, previously subject to operations or cash flows. The portion of Dominion's operating fair value accounting under prior accounting guidance, are revenue related to buy/sell activity for the years 2004, 2003, and recognized as revenue or expense on a gross basis at the time 2002 was 2.1 %,1.5%, and 1.6% respectively. Reported production of contract performance, settlement or termination. -. volumes are not impacted, as only the initial sale of Dominion's production is included inreported production volumes. It is esti-Other mated that approximately 55% of Dominion's 2004 oil production Dominion enters into buy/sell and related agreements as a means to was marketed through the use of one or more crude oil buy/sell reposition its offshore Gulf of Mexico crude oil production to more liquid agreements. See Note 2 to the Consolidated Financial Statements.

Results of Operations Presented below is a summary of contributions by operating segments to net income:

Year Ended December 31, 2004 2003 2002 Net Diluted Net Diluted Net Diluted Income EPS Income EPS Income EPS (millions. except per share amountsl Dominion Generation $ 525 $ 1.59 $ 512 $ 1.60 $ 561 $ 1.98 Dominion Energy 190 0.57 346 1.09 268 0.95 Dominion Delivery 466 1.41 453 1.42 422 . 1.49 Dominion Exploration & Production 595 1.80 415 1.30 380 1.34 Primary operating segments 1,776 5.37 1,726 5.41 1,631 5.76 Corporate and Other (527) (1.59) (1,403) 14.41) (269) (0.94)

Consolidated $1,249 $ 3.78 $ 318 $ 1.00 $1,362 $ 4.82 D 2004I/Page 23

Overview result of its exit from certain energy trading activities. The 2004 vs. 2003 charge is based on Dominion's evaluation of preliminary bids Dominion earned $3.78 per diluted share on net income of $1.2 bil- received from third parties, reflecting the expected amount of lion, an increase of $2.78 per diluted share and $°31 million. The per consideration that would be required by a third party for its share amount includes approximately $0.14 of share dilution, assumption of Dominion's interest inthe contract; reflecting an increase inthe average number of common shares * $61 million of after-tax losses related to the discontinuance of outstanding during 2004. hedge accounting for certain oil hedges resulting from an The combined net income contribution of Dominion's primary interruption of oil production inthe Gulf of Mexico caused by operating segments increased $50 million during 2004. See Note Hurricane Ivan, and subsequent changes in the fair value of 27 to the Consolidated Financial Statements for information about those hedges during the third quarter; Dominion's operating segments. The increase is primarily due to: * $61 million of after-tax charges related to Dominion's

• A lower contribution from regulated electric generation investment in and planned divestiture of DCI assets; operations primarily due to the elimination of fuel deferral * $43 million of net after-tax charges resulting from the accounting for the Virginia jurisdiction, which resulted in the termination of certain long-term power purchase agreements; recognition of fuel expenses in excess of amounts recovered in * $13 million of after-tax losses associated with Dominion's fixed fuel rates. These higher fuel costs were partially offset by telecommunications business, which was sold during 2004; a reduction in capacity expenses due to the termination of partially offset by

• A $28 million after-tax benefit associated with the disposition certain long-term power purchase agreements and increased of CNG International's (CNGI) investment inAustralian pipeline revenue due to favorable weather and customer growth; assets that were sold during 2004.

• Net realized gains (including investment income) associated with nuclear decommissioning trust fund investments as Additionally, the improved consolidated results reflect the impact of significant specific items recognized in2003. These items were opposed to net realized losses (including investment income) reported inthe Corporate and Other segment and are discussed in during the prior year; further detail below.

• A loss from energy trading and marketing activities, reflecting comparatively lower price volatility on natural gas option 2003 vs. 2002 positions and the effect of unfavorable price changes on Dominion earned $1.00 per diluted share on net income of $318 mil-electric trading margins, partially offset by favorable margins in lion, a decrease of $3.82 per diluted share and $1.0 billion. The per coal trading and marketing; share decrease includes approximately $0.13 of share dilution,

• A higher contribution from nonregulated retail energy marketing reflecting an increase inthe average number of common shares out-operations, primarily reflecting an increase inaverage customer standing during 2003.

accounts and higher electric and gas margins: and The combined net income contribution of Dominion's primary operating segments increased $95 million in2003. This increase

• A higher contribution from exploration and production largely reflects the benefits of higher natural gas prices during operations due to favorable changes inthe fair value of certain 2003 on safes of Dominion's gas and oil production as well as oil options, higher average realized prices for gas and oil and margins associated with gas trading activities. This increased the recognition of business interruption insurance revenue contribution by the operating segments was more than offset by associated with the recovery of delayed gas and oil production significant specific charges recognized in 2003 and reported in the due to Hurricane Ivan. Results were also affected by the Corporate and Other segment, including:

recognition of revenue inconnection with deliveries under * $750 million of after-tax losses associated with Dominion's volumetric production payment (VPP) agreements, partially discontinued telecommunications business; offset by lower gas production, reflecting the sale of mineral * $122 million of after-tax incremental expenses associated with rights under the VPP agreements. Hurricane Isabel;

• $96 million of after-tax charges for DCI asset impairments; Inaddition to the higher contribution by the operating segments

• $69 million of after-tax charges for asset impairments related in2004, the consolidated results include the impact of several to certain investments held for sale; specific items recognized in2004 and reported in the Corporate * $104 million of after-tax charges associated with the and Other segment, including: termination of certain long-term power purchase agreements

• A $112 million after-tax charge reflecting Dominion's valuation and the restructuring of power sales agreements; and of its interest ina long-term power tolling contract, which is * $16 million of after-tax severance costs for workforce subject to a planned divestiture in the first quarter of 2005, as a reductions.

D 2004/ Page 24

Analysis of Consolidated Operations Presented below are selected amounts related to Dominion's results of operations:

Year Ended December 31, 2004 2003 2002 (millions)

Operating Revenue Regulated electric sales $5,180 $4,876 $4,856 Regulated gas sales 1,422 1,258 876 Nonregulated electric sales 1,249 1,130 1,017 Nonregulated gas sales 2,082 1,718 778 Gas transportation and storage 802 740 705 Gas and oil production 1,636 1,503 1,334 Other 1,601 853 652 Operating Expenses Electric fuel and energy purchases, net 2,162 1,667 1,447 Purchased electric capacity 587 607 691 Purchased gas, net 2,927 2,175 1,159 Liquids, pipeline capacity and other purchases - 1,007 468 159 Other operations and maintenance 2,748 2,908 2,190 Depreciation, depletion and amortization 1,305 1,216 1,258 Other taxes 519 476 429 Other income (loss) 186 (40) 103 Interest and related charges . 939 975 945 Income tax expense . . 700 597 681 Loss from discontinued operations, net of taxes (15) (642)

Cumulative effect of changes inaccounting principles, net of taxes - 11 An analysis of Dominion's results of operations for 2004 (Fairless) inJune 2004, partially offset by decreased revenue at compared to 2003 and 2003 compared to 2002 follows. certain other stations resulting from lower generation volumes;

• A $140 million decrease inrevenue from energy trading and 2004 vs. 2003 marketing activities reflecting decreased margins inelectric Operating Revenue trading due to unfavorable price movements; and Regulated electric sales revenue increased 6% to $5.2

• A $19 million decrease due to the sale of CNGl's generation billion, primarily reflecting: assets in December 2003.

• A $231 million increase due to the impact of a comparatively nigher Nonregulated gas sales revenue increased 21% to $2.1 fuel rate on increased sales volumes. The rate increase resulted from billion, predominantly due to:

the settlement of a fuel rate case inDecember 2003. This increase in

• A $279 million increase inrevenue from producer services regulated electric sales revenue was more than offset byan increase operations, reflecting higher prices ($157 million) and increased inElectric fuel and energypurchases. net expense; volumes ($122 million). This increase innonregulated gas sales

• A $24 million increase associated with favorable weather; revenue was largely offset by a corresponding increase in

• A $49 million increase from customer orowth associated with Purchased gas, netexpense; new customer connections; and

• A $131 million increase inrevenue from nonregulated retail

• An $18 million increase due to lost revenue in2003 as a result enargy marketing operations, reflecting increased volumes ($55 of outages caused by Hurricane Isabel. million) and higher prices ($76 million);

Regulated gas sales revenue increased 13% to $1.4 billion,

• A $61 million increase inrevenue from sales of gas purchased by largely resulting from a $198 million increase due to higher rates for exploration and production operations to facilitate gas transportation regulated gas distribution operations primarily related to the recovery of and satisfy other agreements. This increase innonregulated gas higher gas prices and a $20 million increase resulting from the return of sales revenue was largely offset by a corresponding increase in customers from Energy Choice programs, partially offset by an $87 mil- Purchasedgas, net expense; partially offset by lion decrease associated with milder weather and lower industrial sales.

• A $108 miillion decrease inrevenue from energy trading and The effect of this net increase inregulated gas sales revenue was marketing activities due to comparatively lower price volatility on largely offset by a comparable increase inPurchasedgas, net expense. natural gas option positions.

Nonregulated electric sales revenue increased 11% to

$1.2 billion, primarily reflecting the combined effects of:

• A $181 million increase inrevenue from nonregulated retail energy marketing operations reflecting increased volumes

($165 million) and higher prices ($16 million);

• A $97 million increase inrevenue from merchant generation operations, largely due to the commencement of commercial operations at the 1,096 megawatt Fairless Energy power station D 2004/ Page 25

1.

Gas transportation and storage revenue increased 8%to

$802 million, primarily reflecting:

• An $83 million increase associated with nonregulated retail

• A $29 million increase due to the August 2003 reactivation of energy marketing operations, reflecting increased volumes ($56 the Cove Point LNG facility, which was acquired by Dominion in million) and higher prices ($27 million);

September 2002; and

• A$66 million increase from gas transmission operations due to

• A $27 million increase inrevenue from gas transmission increased gathering and extraction activities and higher gas operations primarily reflecting increased transportation, usage; and storage, gathering and extraction revenues.

• A$58 million increase related to purchases of gas by Gas and oil production revenue increased 9%to $1.6 billion exploration and production operations to facilitate gas as a result of: transportation and satisfy other agreements, as discussed

• A $37 million increase inrevenue from oil production, largely above in Nonregulatedgas sales revenue.

reflecting higher volumes; and Liquids, pipeline capacity and other purchases expense

• A $180 million increase inrevenue recognized related to increased 115% to $1.0 billion, primarily reflecting a $348 million deliveries under VPP transactions; partially offset by increase inthe cost of coal purchased for resale, a$105 million

• A $72 million decrease inrevenue from gas production, primarily increase inemission credits purchased and a$108 million increase reflecting the sale of mineral rights under the VPP agreements.

related to purchases of oil by exploration and production oper-Other revenue increased 88% to $1.6 billion, largely due to: ations, each of which are discussed in Otherrevenue.

• A $384 million increase incoal sales revenue resulting fro m Other operations and maintenance expense decreased 6%

higher coal prices and increased sales volumes; to $2.7 billion, resulting from:

• A $120 million increase insales of emissions credits reflecting

• A$113 million net benefit due to favorable changes inthe fair higher prices and increased sales volumes; and value of certain oil options related to exploration and

• A $109 million increase inrevenue from sales of purchased oil production operations. During 2004, Dominion effectively by exploration and production operations. settled certain oil options not designated as hedges by entering These increases in other revenue were largely offset by corre- into offsetting option positions that had the effect of preserving sponding increases in Liquids, pipeline capacity and otherpur- approximately $120 million inmark-to-market gains attributable chases expense. Other revenue for 2004 also includes $100 million to favorable changes intime value; and from the recognition of business interruption insurance revenue

• The impact of the following charges recognized in2003:

associated with the recovery of delayed gas and oil production due * $197 million of incremental restoration expenses associated to Hurricane Ivan. with Hurricane Isabel; Operating Expenses and Other Items

• $108 million of charges from asset and goodwill impairments Electric fuel and energy purchases, net expense associated with DCI's financial services operations; increased 30% to $2.2 billion, primarily reflecting: * $105 million of charges associated with the termination of

• A $408 million increase related to regulated utility cpe ations certain long-term power purchase agreements; resulting from the combined effects of an increas3 inthe fixed fuel

• A $64 million charge for the restructuring of certain electric rate and the elimination of fue! deferral accounting for the Virginia sales contracts recorded as derivative assets; jurisdiction, which resulted inthe recognition of fuel expenses in

• A $60 million goodwill impairment associated with the excess of amounts recovered infixed fuel rates. The increase also purchase of the remaining interest inthe reflects higher generation volumes inthe current year; telecommunications joint venture, Dominion Fiber Ventures,

• A $162 million increase related to nonregulated retail energy LLC (DFV), held by another party; marketing operations reflecting increased volumes ($153

• A $28 million charge related to severance costs for million) and higher prices ($9 million); workforce reductions; and

• An $88 million increase related to merchant generation

• A $22 million impairment related to CNGI's generation operations, largely due to the commencement of commercial assets that were sold in Decemoer 2003.

operations at Fairless, partially offset by decreased fuel These benefits were partially offset by the following charges expense at certain other stations resulting from lower and incremental expenses recognized in 2004:

generation volumes; partially offset by

• A$184 million charge related to the valuation of Dominion's

• A $163 million decrease related to energy trading and interest ina long-term power tolling contract; marketing activities.

• $96 million of losses related to the discontinuance of hedge Purchased gas, net expense increased 35% to $2.9 billion, accounting for certain oil hedges resulting from an interruption principally resulting from:1 of oil production inthe Gulf of Mexico caused by Hurricane

• A $274 million increase associated with producer services Ivan, and subsequent changes inthe fair value of those hedges operations, reflecting higher prices ($159 million) and increased during the third quarter; volumes ($115 million), as discussed above in Nonregulatedgas

• $72 million of charges associated with the impairment of sales revenue; retained interests from mortgage securitizations and venture

• A $130 million increase associated with regulated gas sales capital and other equity investments held by DCI; discussed above inRegulated gas sales revenue;

• $71 million of net expenses associated with the termination of certain long-term power purchase agreements; D 20041 Page 26

• An approximate $60 million increase incosts related to gas and 2003 vs. 2002 oil production activities; Operating Revenue

• An $18 million increase inreliability expenses associated with Regulated electric sales revenue increased less than 1%to utility operations primarily due to increased tree-trimming; $4.9 billion, primarily reflecting the combined effects of:

• A $13 million increase related to salaries, wages and benefits

• A $54 million increase from customer growth associated with resulting from a $60 million increase in pension and medical new customer connections; benefits and a $46 million increase due to wage increases and

• A S42 million increase from higher fuel rate recoveries. Fuel other factors, partially offset by an $89 million decrease in rate recoveries were generally offset by a comparable increase incentive-based compensation expense due to failure to meet in fuel expense and did not materially affect net income; and targeted earnings goals; and

• A $103 million decrease associated with milder weather.

• $10 million of expenses associated with the sale of natural gas Regulated gas sales revenue increased 44% to $1.3 billion, and oil assets in British Columbia, Canada. primarily due to the combined impact of a$289 million increase due to Depreciation, depletion and amortization expense higher rates for regulated gas distribution operations primarily related to (DD & A) increased 7%to $1.3 billion, largely due to incremental the recovery of higher gas prices and a $79 million increase associated depreciation expense resulting from property additions, including with comparably colder weather inthe first and fourth quarters of 2003.

those resulting from the consolidation of certain variable interest The effect of this net increase inregulated gas sales revenue was entities as a result of adopting FIN 46R at December 31, 2003. largely offset by a comparable increase inPurchasedgas, net expense.

Other taxes increased 9%to $519 million, primarily due to Nonregulated electric sales revenue increased 11 % to higher gross receipts taxes and higher severance and property $1.1 billion, primarily reflecting the combined effects of:

taxes associated with increased commodity prices.

• A $77 million increase inrevenue from merchant generation Other income increased to $186 million from a net loss of $40 operations, reflecting higher volumes ($59 million) and higher prices million, primarily reflecting: ($18 million). The increase involumes can be attributed to fewer

• A $61 million increase resulting from net realized gains outage days at the Millstone Power Station in2003 and a full years sales from generating units placed into service during 2002; (including investment income) associated with nuclear decommissioning trust fund investments as opposed to net

• A $76 million increase inrevenue from nonregulated retail realized losses (including investment income) during the prior energy marketing operations, primarily as a result of customer year; growth, including the acquisition of new customers previously

• A $23 million benefit associated with the disposition of CNGI's served by other energy companies during 2003; and investment inAustralian pipeline assets that were sold during

• A $43 million decrease inrevenue from energy trading and 2004; and marketing activities due to unfavorable changes inthe fair value

• The impact of the following charges recognized in2003, which of derivative contracts held for trading purposes and the impact did not recur in2004: of adopting EITF 02-3, partially offset by increased margins.

• $57 million of costs associated with the acquisition of DFV Nonregulated gas sales revenue increased 121% to $1.7 senior notes; billion, primarily reflecting'

• $27 million for the reallocation of equity losses between

• An $82 million increase inrevenue from retail energy marketing Dominion and the minority interest owner of DFV; and ' operations, reflecting higher prices ($78 million) and higher

• A $62 million impairment of CNGI's investment inAustralian volumes ($4 million);

pipeline assets held for sale.

• A $659 million increase inrevenue from producer services Income taxes-Dominion's effective tax rate decreased 3.0% operations, reflecting higher prices ($467 million) and higher to 35.6% for 2004, reflecting an increase in the valuation allow- volumes ($192 million); and ance for 2003 with no comparable increase in 2004, partially offset

• A $208 million increase inrevenue from energy trading and by increases in2004 inutility plant differences and other factors. marketing activities due to higher margins, favorable changes Loss from discontinued operations decreased to $15 million in the fair value of derivative contracts held for trading from $642 million, primarily reflecting the sale of Dominion's ' purposes and the impact of adopting EITF 02-3.

discontinued telecommunications operations during May 2004 and Gas and oil production revenue increased 13% to $1.5 bil-the impact of the following charges recognized in2003: lion primarily due to higher average realized prices for gas and oil.

• Impairment of network assets and related inventories of $566 It also includes $43 million of revenue recognized related to deliv-million. Dominion did not recognize any deferred tax benefits' eries under a volumetric production payment transaction.

related to the impairment charges, since realization of tax Other revenue increased 31 % to $853 million, primarily benefits isnot anticipated at this time based on Dominion's reflecting the combined effects of:

expected future tax profile. Inaddition, Dominion increased the

• A $49 million increase incoal sales revenue; valuation allowance on deferred tax assets recognized by its telecommunications investment, resulting ina $48 million increase indeferred income tax expense; and

• Telecommunications operating losses of $28 million.

D 2004 / Page 27

• A $115 million increase, resulting from a change in the classification of coal purchases from other revenue to expense

• A $15 million decrease in expenses associated with nuclear under EITF 02-3 beginning in2003: outages for refueling.

• $94 million of emissions credit sales that began in2003; Other taxes increased 11 % to $476 million, primarily due to

• A $26 million increase insales of extracted products; and higher severance taxes and gross receipts taxes, as well as the

• An $81 million decrease in revenue associated with Dominion effect of a favorable resolution of sales and use tax issues in 2002.

financial services operations, reflecting the winding-down Such benefits were not recognized in2003.

under Dominion's divestiture strategy. Other income decreased 138% to a net loss of $40 million, Operating Expenses and Other Items which included the following items:

Electric fuel and energy purchases expense increased * $57 million of costs associated with the acquisition of DFV senior 15% to $1.7 billion, primarily reflecting: notes;

• A $154 million increase associated with energy trading and * $27 million for the reallocation of equity losses between marketing activities and nonregulated retail energy marketing Dominion and the minority interest owner of DFV; operations, primarily resulting from higher volumes purchased * $62 million for the impairment of certain equity-method and the reclassification of certain purchase contracts due to the investments; and implementation of EITF 02-3; and

• A $32 million increase innet realized losses (including

• A $68 million increase related to regulated utility operations, investment income) associated with nuclear decommissioning including $42 million associated with rate recovery in2003 trust fund investments.

revenue and the recognition of $14 million of previously Partially offsetting these reductions to other income was an deferred fuel costs not recovered under the 2003 settlement of increase of $28 million, reflecting equity losses on Dominion's the Virginia jurisdictional fuel rate case. investment inDFP in2002; DFV was consolidated beginning inthe first Purchased electric capacity expense decreased 12% to quarter of 2003. In2003, the operating losses of DFV's subsidiary,

$607 million, reflecting scheduled rate reductions on certain non- Dominion Telecom, Inc.. were classified indiscontinued operations.

utility generation supply contracts ($54 million) and lower pur- Income taxes-Dominion's effective tax rate increased 5.3% to chases of capacity for utility operations ($30 million), resulting 38.6% for 2003. The increase primarily resulted from the expiration of from the termination of several long-term supply contracts. nonconventional fuel credits beginning in2003, an increase inthe valu-Purchased gas expense increased 88% to $2.2 billion, ation allowance related to the impairment of goodwill associated with primarily reflecting: the telecommunications investment and federal loss carryforwards at

• A $647 million increase associated with producer services CNGI and DCI that are not expected to be utilized, partially offset by a operations, reflecting higher prices ($459 million) and higher reduction inCanadian tax rates applied to deferred tax balances.

volumes ($188 million); and Loss from discontinued operations reflects the results of

• A $363 million increase associated with regulated gas operations of Dominion's telecommunications business, which is operations discussed above inRegulatedgas sales revenue. classified as held for sale. The loss includes the following:

• Impairment of network assets and related inventories of $566 Liquids, pipeline capacity and other purchases expense million. Dominion did not recognize any deferred tax benefits increased 194% to $468 million, reflecting primarily the related to the impairment charges, since realization of tax benefits reclassification of certain purchase contracts for transportation, stor-isnot anticipated at this time based on Dominion's expected future age, coal and emissions allowances due to the adoption of EITF 02-3.

tax profile. Inaddition, Dominion increased the valuation allowance Other operations and maintenance expense rose 33% to on deferred tax assets recognized by its telecommunications

$2.9 billion, primarily reflecting the following specific items:

investment resulting ina $48 million increase indeferred income

• $197 million of incremental restoration expenses associated tax expense; and with Hurricane Isabel;

• Telecommunications operating losses of $28 million.

• $108 million of asset and goodwill impairments associated with DCI's financial services operations; Cumulative effect of changes in accounting principles-

• $105 million of expenses associated with the termination of During 2003 Dominion was required to adopt several new certain long-term power purchase contracts used inelectric accounting standards, resulting in a net after-tax gain of $11 mil-utility operations; lion which included the following:

• A $64 million charge for the restructuring of certain electric

• A $180 million after-tax gain (SFAS No. 143), partially offset by; sales contracts recorded as derivative assets;

• A $67 million after-tax loss (EITF 02-3);

• A $60 million goodwill impairment associated with the

• A $75 million after-tax loss (Statement 133 Implementation purchase of the remaining interest in the telecommunications Issue No. C20); and joint venture held by another party;

• A $27 million after-tax loss (FIN 46R).

• $86 million of accretion expense for AROs;

• An $87 million increase in expense resulting from a decrease in net pension credits and an increase inother postretirement benefit costs; partially offset by D 2004/ Page 28

Outlook-Dominion Dominion Generation's net income contribution increased $13 Dominion believes its operating businesses will provide growth in million, primarily reflecting:

net income on a per share basis, including the impact of higher

• Higher fuel expenses incurred by the regulated utility expected average shares outstanding, in 2005. operations due to the elimination of fuel deferral accounting Growth factors include: which resulted inthe recognition of fuel expenses inexcess of

• Continued growth inutility customers; amounts recovered infixed fuel rates. The increase infuel

• Reduced electric capacity expenses, resulting from the termination expenses also reflects higher generation volumes; of long-term power purchase agreements;

• Higher regulated electric sales due to customer growth in the

• Oil production growth, reflecting a full year of Devils Tower and electric franchise service area, primarily reflecting an increase Front Runner operations; innew residential customers, comparably favorable weather,

• A contribution from the operations of three USGen power lost revenue in2003 due to outages associated with Hurricane stations acquired inJanuary 2005; Isabel, and the impact of the economy and other factors;

• Higher contribution from Cove Point operations due to

• Net realized gains (including investment income) associated with expansion of the facility; and nuclear decommissioning trust fund investments as opposed to net

• A contribution from the Kewaunee nuclear power plant, realized losses (including investment income) during the prior year;'

expected to be acquired inthe first half of 2005. A higher contribution from coal trading and marketing primarily The growth factors will be partially offset by: due to higher coal prices and increased sales volumes; and

• Higher expected Virginia jurisdictional fuel expenses;

• Reduced purchased power capacity expenses due to the termination

• A lower contribution from Millstone resulting from an of long-term power purchase agreements inconnection with the additional refueling outage; purchase of the related nonutility generating facilities.

• Higher expected operating expenses for gas and oil production; 2003 vs. 2002

• An increase in incentive-based compensation expense if earnings targets are met; and Increase

• Increased interest expense. (Decrease)

Amount EPS Based on these projections, Dominion estimates that cash flow from (millions, except EPS) operations will increase in2005, as compared to 2004. Management Revenue reallocation $(57) $(0.201 believes this increase will provide sufficient cash flow to maintain or Regulated electric sales:

grow Dominion's current dividend to common shareholders. Weather (42) (0.15)

Customer growth 23 0.08 Merchant generation margins 18 0.06 Segment Results of Operations Capacity expenses . 29 0.10 Dominion Generation Fuel settlement (9) (0.031 Dominion Generation includes the generation operations of Domin- Utility outages (13) (0.04)

Other 2 0.01 ion's electric utility and merchant fleet as well as coal and emis- Share dilution - (0.21) sions trading and marketing activities. Change innet income contribution 5(49) $(0.38) 2004 2003 2002 (mitlions, except EPS) Dominion Generation's net income contribution decreased $49 Net income contribution s 525 $ 512 5561 million, primarily reflecting:

EPS contribution 51.59 51.60 - $1.98

• A change in the allocation of electric utility base rate revenue Electricitysupplied (million mwhrs) 112 105 101 beginning in2003 among Dominion Generation, Dominion mwhrs = megawatt hours Energy and Dominion Delivery;

• A decrease inregulated electric sales due to comparably milder Presented below, on an after-tax basis, are the key factors summer weather, resulting from adecrease incooling degree days in impacting Dominion Generation's operating results: 2003, partially offset by an increase inheating degree days in2003;

• An increase inregulated electric sales due to customer growth 2004 vs. 2003 in the electric franchise service area, primarily reflecting an Increase increase in new residential customers; lDecreasel Amount EPS

• A higher contribution from merchant generation operations due to fewer outage days at the Millstone Power Station in2003 (millions, except EPS)

Fuel expenses inexcess of rate recovery 511151 S(0.36) and a full year's contribution from gas-fired generating units Regulated electric sales: placed into service during 2002; Weather 10 0.03

• Scheduled decreases incapacity expenses under certain power customer growth 20 0.06 Nuclear decommissioning trust performance 38 0.12 purchase agreements; Coal trading and marketing 31 0.10

• Recognition of previously deferred fuel costs in connection with Capacity expenses 36 0.11 Other (7) (0.02) the 2003 Virginia fuel rate settlement and Share dilution - (0.05)

• Increased utility outage expenses, reflecting the refueling Change innet income contribution $ 13 $10.011 activities at nuclear facilities in2003.

D 2004/ Page 29

Dominion Energy Dominion Energy's net income increased $78 million, primarily reflecting:

Dominion Energy includes Dominion's electric transmission,

• An increase inthe contribution of energy trading and marketing natural gas transmission pipeline and storage businesses, an LNG activities, reflecting an increase inmargins on settled contracts, facility, certain natural gas production, energy trading and partially offset by adecrease innet mark-to-market gains on marketing operations and producer services which includes derivative contracts; aggregation of gas supply and related wholesale activities.

• An increase attributable to a reduction innet losses on the economic hedges of Dominion Exploration & Production gas 2004 2003 2002 production described inSelected Information-Energy Trading Imillions. except EPS)

Activities:

Net income contribution S190 $ 346 S268 EPS contribution

• An increase inelectric transmission margins due to customer

$0.57 S1.09 $0.95 growth and other factors, partially offset by the impact of Gas transportation throughput (bcf1 704 .614 597 unfavorable weather; bcf = billion cubic feet

• A contribution from the Cove Point LNG facility due to its reactivation inAugust 2003; and Presented below, on an after-tax basis, are the key factors

• A change inthe allocation of electric base rate revenue among impacting Dominion Energv's operating results.: Dominion Generation, Dominion Energy and Dominion Delivery effective January 1,2003; 2004 vs. 2003 Dominion Delivery Increase Dominion Delivery includes Dominion's regulated electric and gas (Decrease) distribution and customer service business, as well as non-Amount EPS regulated retail energy marketing operations.

(millions, except EPS)

Energy trading and marketing $11161 $(0.37) 2004 2003 2002 Economic hedges 112) . (0.041 (millions, except EPS)

Electric transmission revenue (15) (0.051 Net income contribution $ 400 S453 $ 422 Other 113) (0.041 EPS contribution $1.41 $1.42 $1.49 Share dilution (0.02)

Electricity delivered Imillion mvvhrs) 78 75 75 Change in net income contribution $(156) 5(0.521 Gas throughput (bcf) 371 373 364 Dominion Energy's net income contribution decreased $156 mil-Presented below, on an after-tax basis, are the key factors lion, primarily reflecting:

impacting Dominion Delivery's operating results:

• A loss from energy trading and marketing activities, reflecting comparatively lower price volatility on natural gas option 2004 vs. 2003 positions and the effect of unfavorable price changes on Increase electric trading margins; l(ecrease}

• A decrease attributable to unfavorable price movements in Amount EPS 2004 on the economic hedges of Dominion Exploration &

(millinis, except EP'S)

Production gas production described in Selected Information-- Weather S (51 . $(0.021 Energy TradingActivities, Customer growth-utility operations 9 0.03

• Lower electric transmission revenue primarily due to decreased Nonregulated retail energy marketing wheeling revenue resulting from lower contractual volumes and operations . 32 0.10 Reliability expenses 111l f (0.031 unfavorable market conditions; and Other (121 (0.04)

• Other factors including losses from asset and price risk Share dilution - (0.05) management activities related to intersegment marketing. Change in net income contribution S 13 $(0.01]

2003 vs. 2002 Dominion Delivery's net income contribution increased $13 million, Increase primarily reflecting:

(Decrease)

• A decrease in regulated gas sales due to comparably milder Amount EPS winter weather inregulated gas service territories; partially

[millions, except EPS) offset by an increase in regulated electric sales resulting from Energy trading and marketing $12 S 0.05 comparably favorable weather inregulated electric service Economic hedges 33 0.12 Electric transmission margins 11 0.04 territories; Cove Point operations 9 0.03

• Customer growth inthe electric and gas franchise service Revenue reallocation 7 0.02 areas, primarily reflecting new residential electric customers:

Other 6 0.02

• A higher contribution from nonregulated retail energy Share dilution - (0.141 marketing operations, primarily reflecting an increase in Change in net income contribution $78 $ 0.14 average customer accounts and higher electric and gas margins; D 2004 IPage 30

• Higher reliability expenses, primarily due to increased tree Presented below, on an after-tax basis, are the key factors trimming; and I. '- impacting Dominion Exploration & Production's operating results:

• Other factors, including a decrease innet pension credits.

2004 vs. 2003 2003 vs. 2002

- Increase Increase (Decrease)

(Decrease) Amount EPS Amount EPS (millions, except EPS) millions, except EPS) VPPrevenue $114 $0.36 Revenue reallocation $ 50 S 0.18 Business interruption insurance 61 0.19 Customer growth-utility operations .10 0.03 Gas and oil-production . 1551 . (0.17)

Weather (5) (0.02) Gasandoil-prices - 49 - 0.15 Income taxes (9) . 10.03) Operations and maintenance 26 0.08 Other 115) (0.05) DD&A-production 13 0.04 Share dilution - (0.18) DD&A-rate (301 . . (0.09)

Change in net income contribution - . $31 S(0.07) Other 2 0.01 Share dilution .. . . . . (0.071 Dominion Delivery's net income contribution increased $31 million, Change in net income contribution - St180 $ 0.50 primarily reflecting:

• A change in the allocation of electric base rate revenue among Dominion Exploration & Production's net income contribution Dominion Generation, Dominion Energy and Dominion Delivery increased $180 million, primarily reflecting:

effective January 1,2003;

• Recognition of revenue inconnection with deliveries under the

• Customer growth inthe electric and gas franchise service VPP agreements; areas, primarily reflecting new residential electric customers;

• The recognition of business interruption insurance revenue

• A decrease inregulated electric sales due to comparably milder associated with the recovery of delayed gas and oil production weather inelectric utility service territories, offset by an due to Hurricane Ivan; increase inregulated gas sales due to comparably colder

• Lower gas production reflecting the sale of mineral rights under weather ingas utility service territories; the VPP agreements;

• A decrease innet pension credits and an increase in other.

• Higher oil production reflecting production related to the postretirement benefit costs; and deepwater Gulf of Mexico Devils Tower project:

• The deferral of 2003 bad debt expenses as a regulatory asset,

• Higher average realized prices for gas and oil; pending future recovery under a bad debt rider approved by the

• Lower operations and maintenance expenses, primarily due to Public Utility Commission of Ohio, effective January 1,2003. favorable changes inthe fair value of certain oil options, partially offset by an increase inproduction costs; and Dominion Exploration & Production

• A higher rate for depreciation, depletion and amortization, Dominion Exploration & Production manages Dominion's gas and primarily reflecting higher industry finding and development oil exploration, development and production business. costs, increased acquisition costs and the effect of the 2004 2003 2002 reduction in reserves attributable to the VPP transactions.

(millions, except EPS) 2003 vs. 2002 Net income contribution $ 595 S 415 $ 380 EPScontribution $ 1.80 S 1.30 $1.34 Increase Gas production (bcf) 359 384 385 (Decrease)

Oil production(millionbbls) 10 9 .10 Amount EPS Average realized prices with hedging (millions, except EPS) resultsill Gas (per mcf)'R s 4.09 $ 3.95 $ 3.40 Gas and oil-prices $133 $ 0.47 Oil (per bbll . . 24.98 24.29 23.28 Gas and oil-production (18) (0.06)

Average prices without hedging results: VPP revenue 27 0.10 2

Gas (per mcfY 1 5.65 4.99 3.03 DD&A-rate (22) (0.08)

Oil (per bbl) 39.07 29.82 24.44 OD&A-production 3 0.01 OD&A(permcfe) $ 1.30 $ 1.20 S 1.12 Operations and maintenance (411 (0.15)

Average production (lifting) cost Iper mcfem 0.92 0.80 0.60 Severance taxes (181 (0.06)

Income taxes (201 (0.07) bbl =barrel Other (9) (0.03) mcf = thousand cubic feet Share dilution - (0.17) mcfe = thousand cubic feet equivalent Change in net income contribution $ 35 5)0.04)

I11 Excludes the effects of the economic hedges discussed under Selected Information-Energy Trading Activities.

(2) Excludes $223 million and $43 million of revenue recognized in 2004 and 2003, Dominion Exploration & Production's net income contribution respectively, under the VPP agreements described in Note 12 to the Consolidated increased $35 million, primarily reflecting:

Financial Statements.

• Higher average realized prices for gas and oil; 13)The exclusion of volumes produced and delivered under the VPP agreements accounted for approximately 75% of the increase from 2003 to 2004 and 8% of

• Lower oil production, reflecting declines inGulf of Mexico shelf the increase from 2002 to 2003. and deepwater production. Lower gas production, reflecting the D 2004IPage 31

sale of mineral rights under a VPP agreement and declines in Note 3 to the Consolidated Financial Statements, including:

Rocky Mountain and Michigan production, was largely offset by

• SFAS No. 143: a $180 million after-tax gain attributable to:

increased Gulf of Mexico gas production; Dominion Generation ($188 million after-tax gain); Dominion

• A higher rate for depreciation, depletion and amortization in Exploration & Production ($7 million after-tax loss); and 2003, primarily reflecting increased acquisition, finding and Dominion Delivery ($1 million after-tax loss);

development costs;

• EITF 02-3: a $67 million after-tax loss attributable to

• Higher operations and maintenance expenses which increased Dominion Energy; in connection with overall higher commodity prices in2003,

• Statement 133 Implementation Issue No. C20: a $75 million that caused an increase inthe demand for equipment, labor after-tax loss attributable to Dominion Generation; and and services;

• FIN 46R: a $17 million after-tax loss attributable to

• Higher severance taxes, resulting from higher gas and oil Dominion Generation; revenue associated with higher commodity prices; and * $197 million of operations and maintenance expense ($122

• Higher income taxes, primarily reflecting the expiration of million after-tax), representing incremental restoration Section 29 production tax credits beginning in2003, partially expenses associated with Hurricane Isabel, attributable offset by a reduction intax rates applied to deferred taxes primarily to Dominion Delivery; associated with Canadian operations.

• A $105 million charge ($65 million after-tax) for the termination of power purchase contracts attributable to Dominion Corporate and Other Generation; Presented below are the Corporate and Other segment's after-tax

• A $64 million charge ($39 million after-tax) for the restructuring results:

and termination of certain electric sales contracts attributable 2004 2003 2002 to Dominion Generation; and -

Imillions, except EPS amounts) * $26 million of severance costs ($15 million after-tax) for Specific items attributable to workforce reductions during the first quarter of 2003, operating segments S1224) S (220) S 7 DCtoperations (82) (96) 14 attributable to:

Telecommunications operations") 113) 1750) (261

• Dominion Generation ($8 million after-tax);

Other corporate operations (208) 1342) (264)

• Dominion Energy ($2 million after-tax);

Total net expense (527) (1,408 - (2691

• Dominion Delivery ($4 million after-tax); and Earnings per share impact $01.59) S (4.41) $(0.941

• Dominion Exploration & Production ($1 million after-tax).

Si 5 million and $642 million are classified as discontinued operations in2004 sl DCI Operations and 2003, respectively.

DCI recognized a net loss of $82 million in2004; a decrease of $14 Specific Items Attributableto Operating Segments-2004 million as compared to 2003. The decrease primarily resulted from During 2004, Dominion reported net expenses of $224 million in a $20 million reduction inafter-tax charges associated with asset the Corporate and Other segment attributable to its operating impairments.

segments. The net expenses in 2004 primarily related to the DCI recognized a net loss of $96 million in2003, compared to impact of the following: net income of $14 million in2002. The loss resulted primarily from

• A $184 million charge ($112 million after-tax) related to the the recognition of the following charges recognized in2003: $108 valuation of Dominion's interest ina long-term power tolling million ($70 million after-tax) of impairments related to retained contract, attributable to Dominion Generation; interests fromn securitizations, goodwill and other investments, and

• $96 million of losses ($61 million after-tax) related to the the sale of financial assets; and a $26 million valuation allowance discontinuance of hedge accounting for certain oil hedges, established on certain deferred tax assets.

resulting from an interruption of oil production inthe Gulf of Mexico caused by Hurricane Ivan, and subsequent changes in Telecommunications Operations the fair value of those hedges during the third quarter, Dominion's loss from its discontinued telecommunications busi-attributable to Dominion Exploration & Production; and ness decreased $737 million to $13 million in 2004, primarily as a

• $71 million of charges ($43 million after, tax) resulting from the result of its sale inMay 2004 and the impact of certain charges termination of certain long-term power purchase contracts, recognized during 2003 which are discussed below.

attributable to Dominion Generation. Dominion's loss from its telecommunications business increased $724 million to $750 million in 2003, primarily reflecting:

Specific Items Attributableto Operating Segments-2003 * $566 million associated with the impairment of network assets During 2003, Dominion reported net expenses of $220 million in and related inventories. Dominion did not recognize any the Corporate and Other segment attributable to its operating deferred tax benefits related to the impairment charges, since segments. The net expenses in2003 primarily related to the realization of tax benefits is not anticipated at this time based impact of the following: on Dominion's expected future tax profile;

• $21 million net after-tax gain representing the cumulative

• A $48 million increase indeferred tax expense as a result of effect of adopting new accounting principles, as described in the increase inthe valuation allowance on deferred tax assets; D 2004 / Page 32

Dominion's purchase of the remaining equity interest in DFV During the fourth quarter of 2004, Dominion performed an held by another party for $62 million in December 2003, $60 evaluation of its Clearinghouse trading and marketing operations, million of which was recorded as goodwill and impaired; which resulted in a decision to exit certain energy trading activities

• $57 million ($35 million after-tax) for the costs associated with and instead focus on the optimization of company assets. Begin-Dominion's acquisition of DFV senior notes; and ning in2005, all revenues and expenses from the Clearinghouse's

• $41 million of after-tax operating losses. optimization of company assets will be reported as part of the results of the business segments operating the related assets.

Other Corporate Operations A summary of the changes inthe unrealized gains and losses The net expenses associated with other corporate operations for recognized for Dominion's energy-related derivative instruments 2004 decreased by $134 million as compared to 2003, predom-held for trading purposes, including the economic hedges, during inantly due to a $28 million after-tax benefit associated with the 2004 follows:

disposition of CNGI's investment inAustralian pipeline assets that were sold during 2004, lower interest expense and the impact in Amount 2003 of the charges discussed below. (millions)

The net expenses associated with other corporate operations Net unrealized gain at December 31, 2003 S 33 for 2003 increased by $78 million as compared to 2002, primarily Contracts realized or otherwise settled during the period 15 Net unrealized gain at inception of contracts initiated during the reflecting:

period

• A $22 million ($14 million after-tax) impairment related to Changes invaluation techniques CNGI's generation assets that were sold in December 2003; Other changes infair value 98

• A $62 million ($55 million after-tax) impairment of CNGI's Net unrealized gain at December 31. 2004 $146 investment inAustralian pipeline assets held for sale; and

• A $16 million ($10 million after-tax) loss representing the The balance of net unrealized gains and losses recognized for cumulative effect of adopting FIN 46R. Dominion's energy-related derivative instruments held for trading Selected Information-Energy Trading Activities purposes, including the economic hedges at December 31, 2004, is As previously described, Dominion manages its energy trading, summarized inthe following table based on the approach used to hedging and marketing activities through the Clearinghouse. determine fair value and contract settlement or delivery dates:

Dominion 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 InExcess for purchases and sales of energy-related commodities, including than 1 2-3 3-5 of 5 SourceofFairValue year 1-2years years years years Total coal, natural gas, electricity, oil and emissions credits. Settlements (millions) of contracts may require physical delivery of the underlying Activelyquoted") $105 $15 $5 - - $125 commodity or cash settlement. The Clearinghouse enters into Other external sourcesm - 14 5 $2 - 21 contracts with the objective of benefiting from changes in prices. Models and other For example, after entering into a contract to purchase a commod- valuation methods -

ity, the Clearinghouse typically enters into a sales contract, or a Total $105 $29 $10 $2 - $146 combination of sales contracts, with quantities and delivery or settlement terms that are identical or very similar to those of-the: (1)Exchange-traded and over-the-counter contracts.

(2)Values based on prices from over-the-counter broker activity and industry serv-purchase contract. When the purchase and sales contracts are: ices and, where applicable, conventional option pricing models.

settled either by physical delivery of the underlying commodity or by net cash settlement, the Clearinghouse may receive a net cash margin (arealized gain), or may pay a net cash margin (arealized.. Sources and Uses of Cash loss). Clearinghouse management continually monitors its contract Dominion and its subsidiaries depend on both internal and external positions, considering location and timing of delivery or settlement sources of liquidity to provide working capital and to fund capital for each energy commodity inrelation to market price activity. requirements. Short-term cash requirements not met by cash Inaddition, the Clearinghouse held a portfolio of financial provided by operations are generally satisfied with proceeds from derivative instruments to manage Dominion's price risk associated short:term borrowings. Long-term cash needs are met through with a portion of its anticipated sales of 2004 natural gas pro- sales of securities and additional long-term financing.

duction that had not been considered inthe hedging activities of At December 31, 2004, Dominion had cash and cash equiv-the Dominion Exploration & Production segment.(economic alents of $389 million with $2.4 billion of unused capacity under its hedges). In2004, Dominion Energy recognized a net loss of $22 credit facilities. For long-term financing needs, amounts available million on the economic hedges. As anticipated, Dominion Explora- for debt or equity offerings under currently effective shelf registra-tion & Production sold sufficient volumes of natural gas in 2004 at tions totaled $2.5 billion at February 1,2005.

market prices, which, when combined with the settlement of the economic hedges, resulted ina range of prices for those sales contemplated by the risk management strategy.

D 20041 Page 33

Operating Cash Flows (I) Designations as investment grade are based upon minimum credit ratings assigned by Moody's Investors Service (Moody's) and Standard &Poors Rating As presented on Dominion's Consolidated Statements of Cash Group, adivision of the McGraw-Hill Companies, Inc. (Standard &Poor's) .The Flows, net cash flows from operating activities were $2.8 billion, five largest counterparty exposures, combined, for this category represented

$2.4 billion and $2.4 billion for the years ended December 31, 2004, approximately 16% of the total gross credit exposure.

2003 and 2002, respectively. Dominion's'management believes that (21The five largest counterparty exposures, combined, for this category represented approximately 2%of the total gross credit exposure.

its operations provide a stable source of cash flow sufficient to (3) The five largest counterparty exposures, combined, for this category contribute to planned levels of capital expenditures and maintain or represented approximately 14% of the total gross credit exposure.

grow the dividend on common shares. (4) The five largest counterparty exposures, combined, for this category Dominion's operations are subject to risks and uncertainties represented approximately 3%of the total gross credit exposure.

that may negatively impact the timing or amounts of operating Investing Cash Flows cash flow, including: During 2004, 2003 and 2002, investing activities resulted in net

• Cost-recovery shortfalls due to capped base and fuel rates in cash outflows of $1.3 billion, $3.4 billion, and $4.0 billion effect inVirginia for its regulated electric utility, respectively. Significant investing activities for 2004 included:

• The collection of business interruption insurance proceeds * $1.5 billion of capital expenditures for the construction and associated with the recovery of delayed gas and oil production expansion of generation facilities, environmental upgrades, due to Hurricane Ivan, purchase of nuclear fuel, and construction and improvements of

• Unusual weather and its effect on energy sales to customers gas and electric transmission and distribution assets; and energy commodity prices;

• $1.3 billion of capital expenditures for the purchase and

• Extreme weather events that could disrupt gas and oil development of gas and oil producing properties, drilling and production or cause catastrophic damage to Dominion's electric equipment costs and undeveloped lease acquisitions; distribution and transmission systems;

• $729 million of proceeds from sales of gas and oil mineral

• Exposure to unanticipated changes in prices for energy rights and properties; commodities purchased or sold, including the effect on

• $490 million for the purchase of securities and $466 million for derivative instruments that may require the use of funds to post the sale of securities, primarily related to investments held in margin deposits with counterparties; nuclear decommissioning trusts; and

• Effectiveness of Dominion's risk management activities and

• $132 million in advances and $806 million in reimbursements underlying assessment of market conditions and related related to the Fairless generation project in Pennsylvania.

factors, including energy commodity prices, basis, liquidity, volatility, counterparty credit risk, availability of generation and Financing Cash Flows and Liquidity transmission capacity, currency exchange rates and interest Dominion, Virginia Electric and Power Company Virginia Power) and rates; Consolidated Natural Gas Corhpany (CNG) (collectively the Dominion

• The cost of replacement electric energy inthe event of longer- Companies) rely on bank and capital markets as a significant source than-expected or unscheduled generation outages; of funding for capital requirements not satisfied by cash provided by

• Contractual or regulatory restrictions on transfers of funds the companies' operations. As discussed further in the CreditRat-among Dominion and its subsidiaries; and ings section below, the Dominion Companies' ability to borrow funds

• Timeliness of recovery for costs subject to cost-of-seivice utility or issue securities and the return demanded by investors are rate regulation. affected by the issuing company's credit ratings. In addition, the Credit Risk raising'of external capital is subject to certain regulatory approvals, Dominion's exposure to potential concentrations of credit risk including authorization by the SEC and, in the case of Virginia Power, results primarily from its energy trading, marketing and hedging the Virginia State Corporation Commission (Virginia Commission).

activities and sales of gas and oil production. Presented below is a During 2004, net cash used in financing activities was $1.3 summary of Dominion's gross and net credit exposure as of billion. During 2003 and 2002. net cash flows from financing activ-December 31, 2004 for these activities. Dominion calculates its ities were $853 million and $1.3 billion, respectively. During 2004, gross credit exposure for each counterparty as the unrealized fair the Dominion Companies issued long-term debt (net of exchanged value of derivative contracts plus any outstanding receivables (net debt) and common stock totaling approximately $1.7 billion. The of payables, where netting agreements exist), prior to the applica- proceeds were used primarily to repay debt.

tion of collateral. Credit Facilitiesand Short-Term Debt Gross Net The Dominion Companies use short-term debt, primarily commercial Credit Credit Credit paper, to fund working capital requirements, as a bridge to long-term Exposure Collateral Exposure debt financing and as bridge financing for acquisitions, if applicable. The Imillions)

Investment grade0) $ 784 $23 S 761 levels of borrowing may vary significantly during the course of the year, Non-investment grade" 36 - 36 depending upon the timing and amount of cash requirements not sat-No external ratings:

Internally rated-investment isfied by cash from operations. At December 31,2004, the Dominion gradeQt 299 - 299 Companies had committed lines of credit totaling $3.75 billion. Although Internally rated-non-investment there were no loans outstanding, these lines of credit support commer-grade"] 150 - 150 Total 51,269 $23 $1,246 cial paper borrowings and letter of credit issuances. At December 31, D 2004 / Page 34

2004, the Dominion Companies had the following commercial paper and These provisions apply separately to Dominion Resources, Inc.,

letters of credit outstanding and capacity available under credit facilities: Virginia Power and CNG. If any one of the Dominion Companies or any of that specific company's material subsidiaries fail to make Outstanding Outstanding Facility Facility Commercial Letters of Capacity payment on various debt obligations inexcess of $25 million, the Limit Paper Credit Available lenders could require that respective company to accelerate its (millions) repayment of any outstanding borrowings under the credit facility Three-year revolving and the lenders could terminate their commitment to lend funds to credit facilityl'l $1,500 that company. Accordingly, any defaults on indebtedness by CNG Three-year revolving credit facility'n 750 or any of its material subsidiaries would not affect the lenders' Total joint credit commitment to Virginia Power. Similarly, any defaults on facilities 2.250 $573 $183 $1,494 indebtedness by Virginia Power or any of its material subsidiaries Three-year CNG credit would not affect the lenders' commitment to CNG. However, any facility'3 1,500 - 555 945 default by either CNG or Virginia Power would also affect in like Totals $3,750 $573 $738 $2,439 manner the lenders' commitment to Dominion Resources, Inc.

under the joint credit agreements.

I1) The $1.5 billion three-yearrevolvingcreditfacilitywas entered into in May 2004 and terminates in May 2007. This credit facility can also be used to Although the joint credit agreements contain material adverse support up to 5500 million of letters of credit. change clauses, the participating lenders, under those specific.

121The $750 million three-year revolving credit facility was entered into in May provisions, cannot refuse to advance funds to any of the Dominion 2002 and can also be used to support up to $200 million of letters of credit.

Dominion expects to renew this facility prior to its maturity inMay 2005. Companies for the repurchase of.its outstanding commercial paper.

13)The $1.5 billion three-year credit facility isused to support the issuance of letters of credit and commercial paper by CNG to fund collateral requirements Long-Term Debt under its gas and oil hedging program. The facility was entered into in August During 2004, Dominion Resources. Inc. and its subsidiaries issued 2004 and terminates in August 2007. the following long-term debt:

Inaddition to the facilities above, inJune and August of 2004, Type . Principal Rate Maturity Issuing Company CNG entered into two $100 million letter of credit agreements that Imillionsl terminate inJune 2007 and August 2009, respectively. Additionally, Senior notes $200 5.20% 2016 Dominion Resources, Inc.

Senior notes o100Variable 2006 Dominion Resources, Inc.

inOctober 2004, CNG entered into three letter of credit agreements Senior notes 400 5.00% 2014 CNG totaling $700 million that terminate inApril 2005 and are not Senior notes 177 4.92% 2009 Dominion Canada Finance Corporation expected to be renewed. These five agreements support letter of Total long-term debt credit issuances, providing collateral required on derivative financial issued $877 contracts used by CNG inits risk management strategies for gas and oil production. At December 31, 2004, outstanding letters of credit During 2004, Dominion Resources, Inc. and its subsidiaries under these agreements totaled $900 million. repaid $1.3 billion of long-term debt securities.

Dominion's financial policy precludes issuing commercial paper In2004, Dominion exchanged $219 million of outstanding inexcess of its supporting lines of credit. At December 31, 2004, contingent convertible senior notes for new notes with a con- .

the total amount of commercial paper outstanding was $573 mil- version feature that requires that the principal amount of each lion and the total amount of letter of credit issuances was $738 note be repaid in cash upon conversion.

million, leaving approximately $2.4 billion available for issuance. In 2004, in connection with the acquisition of certain The Dominion Companies are required to pay minimal annual' generating facilities, Virginia Power assumed $109 million of commitment fees to maintain the credit facilities. private placement bonds and $104 million of pollution control Inaddition, these credit agreements contain various terms and bonds. Virginia Power exchanged $106 million of its 2004 Series A conditions that could affect the'Dominion Companies' ability to 7.25% senior notes-due 2017 for $106 million of the private borrow under these facilities. They include maximum debt to total placement bonds. The senior notes have the same financial terms capital ratios, material adverse change clauses and cross-default as the private placement bonds, but are registered securities.

provisions. Common Stock All of the credit facilities include a defined maximum total debt During 2004, Dominion issued 14 million shares of common stock to total capital ratio. As of December 31, 2004, the calculated ratio and received proceeds of $839 million. Of this amount, 7 million for the Dominion Companies, pursuant to the terms of the agree-shares and proceeds of $413 million resulted from the settlement of ments, was as follows:

stock purchase contracts associated with Dominion's 2000 issuance Maximum Actual of equity-linked debt securities. The remainder of the shares issued Company Ratio RatioNl and proceeds received were through Dominion Directs (adividend Dominion Resources. Inc. 65% 55% reinvestment and open enrollment direct stock purchase plan).

Virginia Power 60% 50% employee savings plans and the exercise of employee stock options.

CNG 60% 51% In2005, Dominion Directs and the Dominion employee savings 1t)Indebtedness as defined by the bank agreements excludes certain junior sub- plans will purchase Dominion common stock on the open market ordinated notes payable to affiliated trusts and mandatorily convertible secu- with the proceeds received through these programs, rather than rities that are reflected on the Consolidated Balance Sheets. having additional new common shares issued.

D 2004/ Page 35

InJuly 1998, Dominion was authorized by its Board of Directors of the proceeds are not needed, Dominion has the option to either to repurchase up to the lesser of 16.5 million shares, or $650 mil- cash settle or net share settle the remainder of the second tranche lion of its outstanding common stock. As of December 31. 2004, of the forward agreement inwhole, or inpart, and may elect settle-Dominion had repurchased approximately 12 million shares for ment earlier than the stated maturity date. If Dominion elects to

$537 million, with its last repurchase occurring in2002. InFebruary cash or net share settle any portion of the remainder of the second 2005, inorder to recognize the significant increase inthe size of tranche, the payment isbased on the difference between Dominion's the company and the market value of its common stock since the share price and the applicable forward sale price for the second time of the previous authorization, Dominion's Board of Directors tranche, multiplied by the number of shares being settled.

superseded this authority, with new authority, to repurchase up to If, at December 31, 2004, Dominion had elected a cash settle-the lesser of 25 million shares or $2.0 billion of Dominion's out- ment of the 8 million shares in the second tranche, Dominion standing common stock. would have owed MLI $28 million, of which, $18 million would have represented settlement of the 5 million shares remaining in Forward Equity Transaction the second tranche after the February 2005 settlement. If, at the InSeptember 2004, Dominion entered into a forward equity sale time of cash settlement, Dominion's current share price were agreement (forward agreement) with Merrill Lynch International (MLI),

lower than the forward sale price, Dominion would receive a as forward purchaser, relating to 10 million shares of Dominion's payment from MLI. For every dollar increase (decrease) inthe value common stock. The forward agreement provides for the sale of two of Dominion's stock, the value of the settlement of the shares tranches of Dominion common stock, each with stated maturity dates remaining in the second tranche from MLI's perspective would and settlement prices. Inconnection with the forward agreement, MLI increase (decrease) by $5million.

borrowed an equal number of shares of Dominion's common stock Dominion expects to use proceeds received from physical share from stock lenders and, at Dominion's request, sold the borrowed settlements under the remainder of the second tranche of the shares to J.P. Morgan Securities Inc. IJPM) under a purchase agree-forward agreement to fund part of the cost of acquiring the ment among Dominion, MLI and JPM. JPM subsequently offered the Kewaunee nuclear power plant inWisconsin for $220 million borrowed shares to the public. Dominion accounted for the forward (which is expected to close in the first half of 2005) and the acquis-agreement as equity at its initial fair value but did not receive any ition of three electric generating stations from USGen for $642 proceeds from the sale of the borrowed shares.

million (which closed on January 1,2005).

The use of a forward agreement allows Dominion to avoid equity market uncertainty by pricing a stock offering under then Amounts Available under Shelf Registrations existing market conditions, while mitigating share dilution by At February 1,2005, Dominion Resources, Inc., Virginia Power, and CNG postponing the issuance of stock until funds are needed. Except in had approximately $941 million, $670 million, and $900 million, specified circumstances or events that would require physical respectively, of available capacity under currently effective shelf share settlement, Dominion may elect to settle the forward registrations. Securities that may be issued under these shelf registra-agreement by means of a physical share, cash or net share settle- tions, depending upon the registrant, include senior notes (including ment and may also elect to settle the agreement inwhole, or in medium-term notes), subordinated notes, first and refunding mortgage part, earlier than the stated maturity date at fixed settlement bonds, trust preferred securities, preferred stock and common stock.

prices. Under either a physical share or net share settlement, the In addition, Dominion Resources, Inc., under a separate shelf maximum number of shares deliverable by Dominion under the registration has 6.9 million shares of common stock available terms of the forward agreement was limited to the 10 million exclusively for delivery against stock purchase contracts asso-shares specified inthe two tranches. Assuming gross share ciated with outstanding equity-linked debt securites.

settlement of all shares under the forward agreement, Dominion In December 2004, the SEC granted Dominion's request for would have received aggregate proceeds of approximately $644 financing authorization under the 1935 Act through December 31, million, based on maturity forward prices of $64.62 per share for 2007. This authority replaced the previous financing authority the 2 million shares included inthe first tranche and $64.34 per granted by the SEC, which expired December 31, 2004:

share for the 8 million shares included inthe second tranche.

Credit Ratings However, Dominion elected to cash settle the first tranche in December 2004 and made a payment to MLI for $5.8 million, Credit ratings are intended to provide banks and capital market representing the difference between Dominion's share price and the participants with a framework for comparing the credit quality of applicable forward sale price, multiplied by the 2 million shares. securities and are not a recommendation to buy, sell or hold secu-Dominion recorded the settlement payment as a reduction to common rities. Management believes that the current credit ratings of the Dominion Companies provide sufficient access to the capital stock inits Consolidated Balance Sheet. Additionally, Dominion markets. However, disruptions in the banking and capital markets elected to cash settle 3 million shares of the second tranche in not specifically related to Dominion may affect the Dominion February 2005 and made a payment to MLI for $17.4 million.

Companies' ability to access these funding sources or cause an The remaining 5 million shares of the second tranche must be increase inthe return required by investors.

settled by May 17, 2005. If gross share settlement were elected for Both quantitative (financial strength) and qualitative (business the remainder of the second tranche at its maturity date, Dominion or operating characteristics) factors are considered by the credit would receive aggregate proceeds of approximately $322 million and rating agencies in establishing an individual company's credit would deliver 5 million of its common shares. In the event any or all rating. Credit ratings should be evaluated independently and are D 2004/ Page 36

subject to revision or withdrawal at any time by the assigning

• Performance obligations, audits/inspections, continuation of rating organization. The credit ratings for the Dominion Companies the basic nature of business, restrictions on certain matters are most affected by each company's financial profile, mix of related to merger or consolidation, restrictions on disposition of regulated and nonregulated businesses and respective cash flows, substantial assets; changes in methodologies used by the rating agencies and "event

• Compliance with collateral minimums or requirements related risk,' if applicable, such as major acquisitions. to mortgage bonds; and Credit ratings for the Dominion Companies as of February 1,2005

• Limitations on liens.

follow:. Dominion monitors the covenants on a regular basis in order to Standard ensure that events of default will not occur. As of December 31,

& Poor's Moodj's 2004, there were no events of default under the Dominion Compa-Dominion Resources. Inc. nies' covenants.

Senior unsecured debt securities BBB+ Baal Preferred securities of affiliated trusts 8BB- Baa2 Commercial paper A-2 P-2 Virginia Power Mortgage bonds A- A2 Senior unsecured (including tax-exemptl debt securities BBB+ A3 Preferred securities of affiliated trust BBB- BaaI Preferred stock BB8- Baa2 Commercial paper A-2 P-1 CNG Senior unsecured debt securities BBB+ A3 Preferred securities of affiliated trust BBB-' B1al Commercial paper A-2 P-2 As of February 1,2005, Moody's maintains a negative outlook for its ratings of CNG and Standard & Poor's maintains a negative outlook for its ratings of Dominion Resources, Inc., Virginia Power and CNG.

Generally, a downgrade in an individual company's credit rating would not restrict its ability to raise short-term and long-term financing so long as its credit rating remains "investment grade,"

but it would increase the cost of borrowing. Dominion works closely with both Standard & Poor's and Moody's with the objective of maintaining its current credit ratings. As discussed in Risk Factors and Cautionary Statements That May Affect Future Results, inorder to maintain its current ratings, Dominion may find it necessary to modify its business plans and such changes may adversely affect its growth and earnings per share.

Debt Covenants As part of borrowing funds and issuing debt (both snort-term and long-term) or preferred securities, the Dominion Companies must enter into enabling agreements. These agreements contain cove-nants that, inthe event of default, could result in the acceleration .

of principal and interest payments; restrictions on distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments; and in some cases, the termination of credit commitments unless a waiver of such requirements is agreed to by the lenders/security holders. These provisions are customary, with each agreement specifying which covenants apply. These provisions are not necessarily unique to the Dominion Companies. Some of the typical covenants include:

• The timely payment of principal and interest;

• Information requirements, including submitting financial reports filed with the SEC to lenders; D 2004/ Page 37

Future Cash Payments for Contractual Obligations and Dominion's planned capital expenditures during 2005 are Planned Capital Expenditures expected to total approximately $3.6 billion, which includes the cost Dominion is party to numerous contracts and arrangements of acquiring USGen and certain non-utility generating facilities. For obligating Dominion to make cash payments infuture years. These 2006, planned capital expenditures are expected to be approximately contracts include financing arrangements such as debt agreements $3.0 billion. These expenditures include construction and expansion and leases, as well as contracts for the purchase of goods and of generation facilities, environmental upgrades, construction services and financial derivatives. Presented below is a table improvements and expansion of gas and electric transmission and summarizing cash payments that may result from contracts to distribution assets, purchases of nuclear fuel and expenditures to which Dominion is a party as of December 31, 2004. For purchase explore for and develop natural gas and oil properties. Dominion obligations and other liabilities, amounts are based upon contract expects to fund its capital expenditures with cash from operations terms, including fixed and minimum quantities to be purchased at and a combination of sales of securities and short-term borrowings.

fixed or market-based prices. Actual cash payments will be based Dominion may choose to postpone or cancel certain planned upon actual quantities purchased and prices paid and will likely capital expenditures inorder to mitigate the need for future debt differ from amounts presented below. The table excludes all financings.

amounts classified as current liabilities on the Consolidated Bal-Use of Off-Balance Sheet Arrangements ance Sheets, other than current maturities of long-term debt and Leasing Arrangements interest payable. The majority of current liabilities will be paid in Dominion has an agreement with a voting interest entity (lessor) to cash in2005.

lease the Fairless power station inPennsylvania, which began Less More commercial operations inJune 2004. During construction, Dominion than 1-3 3-5 than 5 1Year years years years Total acted as the construction agent for the lessor, controlled the design (millionsl and construction of the facility and has since been reimbursed for all Long-term debtl) $1,368 $3,948 $1,807 $ 9,810 $16,933 project costs advanced to the lessor. Project costs totaled $898 million Interest payments(2) 974 1,682 1,346 7,339 11,341 at December 31, 2004. Dominion will make annual lease payments of Leases 133 225 184 365 .907 $53 million. The lease expires in2013 and at that time, Dominion may Purchase obligations(3k renew th3 lease at negotiated amounts based on original project costs Purchased electric and current market conditions, subject to lessor approval; purchase capacity for utility Fairless at its original construction cost or sell Fairless, on behalf of operations 509 968 858 3,103 5,438 the lessor, to an independent third party. If Fairless issold and the Fuel used for utility proceeds from the sale are less than its original construction cost, operations 691 673 245 51 1,660 Dominion would be required to make a payment to the lessor inan Fuel used for nonregulated amount up to 70.75% of original project costs adjusted for certain operations 48 76 70 - 194 other costs as specified inthe lease. The lease agreement does not Production handling 56 105 61 27 249 contain any provisions that involve credit rating or stock price trigger Pipeline transportation events.

and storage 82 118 85 95 380 Benefits of this arrangement include:

Energy commodity

• Certain tax benefits as Dominion is considered the owner of the purchases for leased property for tax purposes. As a result, it is entitled to tax resaledo) 527 131 3 - 661 deductions for depreciation not recognized for financial Other 352 254 35 5 646 accounting purposes; and Other Icng-term

• As an operating lease for financial accounting purposes, the liabilities(si:

asset and related borrowings used to finance the construction Financial derivatives-commoditiest 4) 1,084 858 1 - 1,943 of the asset are not included on Dominion's Consolidated Other contractual Balance Sheets. Although this improves measures of leverage obligations 25 32 14 32 103 calculated using amounts reported inDominion's Consolidated Financial Statements, credit rating agencies view lease Total cash payments $5,849. $9,070 $4,709 $20,827 $40,455 obligations as debt equivalents inevaluating Dominion's credit

11) Based on stated maturity dates rather than the earlier redemption dates that profile.

could be elected by instrument holders.

(21 Does not ref lect Dominion's ability to defer distributions related to its junior Securitizations of Mortgages and Loans subordinated notes payable to affiliated trusts.

(31 Amounts exclude open purchase orders for services that are provided on As of December 31, 2004, Dominion held $335 million of retained demand, the timing of which cannot be determined. interests from securitizations of mortgage and commercial loans (41 Represents the summation of settlement amounts, by contracts, due from Dominion if all physical or financial transactions among Dominion and its completed in prior years. Dominion did not securitize or originate counterparties were liquidated and terminated.

(15 Excludes regulatory liabilities, AROs and employee benefit plan obligations any loans in2004. Investors inthe securitization trusts have no that are not contractually fixed as to timing and amount. See Notes 14,15 and recourse to Dominion's other assets for failure of debtors to repay 21to the Consolidated Financial Statements. Deferred income taxes are also excluded since cash payments are based primarily on taxable income for each principal and interest on the underlying loans when due. Therefore, discrete fiscal year. Dominion's exposure to any future losses from this activity is lim-ited to its investment in retained interests.

D 2004/ Page 38

Forward Equity Transaction ... ,..1. t.i ' Dominion anticipates that its unhedged natural gas and oil As described in Financing Cash Flows and Liquidity-Forard. production will act as a natural internal hedge for electric gen-Equity Transaction, in September 2004, Dominion entered into a eration. If gas and oil prices rise, it isexpected that Dominion's forward equity sale agreement relating to 10 million shares of. exploration and production operations will earn greater profits that Dominion's common stock. The use of a forward agreement allows will help offset higher fuel costs and lower profits inDominion's Dominion to avoid equity market uncertainty by pricing a stock < electric generation operations. Conversely, if gas and oil prices offering under then current market conditions, while mitigating fall, it isexpected that Dominion's electric generation operations share dilution by postponing the issuance of stock until funds are will incur lower fuel costs and earn higher profits that will offset needed. If Dominion decides it does not need any or all of the lower profits in Dominion's exploration and production operations.

proceeds, it has the option to cash settle or net share settle the Dominion also anticipates that the fixed fuel rate will lessen the forward sale agreement inwhole, or inpart. impact of seasonally mild weather on its electric generation oper-ations. During periods of mild weather-it is expected that electric Future Issues and Other Matters generation operations will burn less high-cost fuel because Status of Electric Deregulation in Virginia customers will use less electricity, thereby offsetting decreased The Virginia Electric Utility Restructuring Act (Virginia revenues. Alternatively, inperiods of extreme weather, Dominion's Restructuring Act) was enacted in 1999 and established a plan to; higher fuel costs from running costlier'plants are expected to be restructure the electric utility industry inVirginia. The Virginia mitigated by additional revenue as customers use more electricity.

Restructuring Act addressed among other things: capped base Other amendments to the Virginia Restructuring Act were also rates, regional transmission organization (RTO) participation. retail enacted with respect to aminimum stay exemption program, awires choice, the recovery of stranded costs and the functional separa- charges exemption program and allowing the development of a coal-tion of a utility's electric generation from its electric transmission fired generating plant insouthwest Virginia for serving default and distribution operations.:.' . service needs. Under the minimum stay exemption program, large Retail choice has been available to all of Dominion's Virginia customers with a load of 500 kW or greater would be exempt from regulated electric customers since January 1.2003. Dominion has the twelve-month minimum stay obligation under capped rates if also separated its generation, distribution and transmission func- they return to supply service from the incumbent utility at market-tions through the creation of divisions: Virginia codes of conduct based pricing after they have switched to supply service with a ensure that Dominion's generation and other divisions operate competitive service provider. The wires charge exemption program independently and prevent cross-subsidies between the generation would allow large industrial and commercial customers, as well as and other divisions. . . aggregated customers inall rate classes, to avoid paying wires Since the passage of the Virginia Restructuring Act, the com- ' charges by agreeing to market-based pricing upon return to the petitive environment has not developed in Virginia as anticipated. incumbent electric utility. InJanuary 2005, Dominion filed com-In April 2004, the Governor of Virginia signed into law amend- : pliance plans for both of these programs.

ments to the Virginia Restructuring Act and the Virginia fuel factor RTO statute. The amendments extend capped base rates by three and InSeptember 2002. Dominion and PJM Interconnection, LLC (PJM[

one-half years, to December 31, 2010, unless modified or termi- entered into an agreement that provides for, subject to regulatory nated earlier under the Virginia Restructuring Act. In addition to approval and certain provisions, Dominion to become a member of extending capped rates, the amendments - PJM, transfer functional control of its electric transmission facili-

• Lock in Dominion's fuel fact6r provisions until the earlier of July' ties to PJM for inclusion in anew PJM South Region and integrate 1.2007 or the termination of capped rates: its control area into the PJM energy markets. The agreement also

• Provide for a one-time adjustment of Dominion's fuel factor,' allocates costs of implementation of the agreement among the effective July 1,2007 through December 31,2010 (unless capped parties.

rates are terminated earlier under the Virginia Restructuring Act), InOctober 2004, the FERC issued an order conditionally with no adjustment for previously incurred over-recovery or approving Dominion's application to join PJM. Inits order, FERC under-recovery, thus eliminating deferred fuel accounting for the determined that: (i)Dominion's proposed transmission rate treat-Virginia jurisdiction: and ment must conform to a regional transmission rate design, and (ii)

• End wires charges on the earlier of July 1,2007 or the Dominion must assess all available evidence and determine:

termination'of capped rates, consistent with the Virginia whether the requested deferral of expenditures related to the Restructuring Act's original timetable. establishment and operation of an RTO should be recorded as a The risk of fuel factor-related cost recovery shortfalls ma' regulatory asset until the end of the Virginia retail rate cap period. .

adversely impact Dominion's cost structure'during the transition Ina separate order issued inSeptember 2004. FERC granted period, and Dominion could realize the negative economic impact of authority to Dominion subsidiaries with market based rate any such adv6rse event. Conversely, Dominion may experience a authority to charge market based rates for sales of electric energy positive economic impact to the extent that it can reduce its fuel and capacity to loads located within Dominion's service territory factor-related costs for its electric utility generation-related oper-' upon its integration into PJM.

ations. Dominion has made filings with both the Virginia Commission and North Carolina Utilities Commission (North Carolina D 2004/ Page 39

Commission) requesting authorization to become a member of PJM. to numerous risks even in the capped-rate environment. These InOctober 2004, Dominion filed a settlement agreement with the include, among others, exposure to long-term power purchase Virginia Commission resolving most of the issues raised by inter- commitment losses, future environmental compliance require-ested parties inthe proceeding, and hearings were held to address ments, changes in tax laws, nuclear decommissioning costs, the remaining issues. The Virginia Commission approved Dominion's inflation, increased capital costs and recovery of certain other application to join PJM in November 2004 subject to the terms and items.

conditions of the settlement agreement. The North Carolina The enactment of deregulation legislation in 1999 not only Commission evidentiary hearing was held inJanuary 2005. Dominion caused the discontinuance of SFAS No. 71, Accounting for the cannot predict the outcome of this matter at this time. Effects of Certain Types of Regulation, for Dominion's Virginia juris-dictional utility generation-related operations but also caused North Carolina Rate Matter Dominion to review its utility generation assets for impairment and Inconnection with the North Carolina Commission's approval of the long-term power purchase contracts for potential losses at that time.

CNG acquisition, Dominion agreed not to request an increase in Significant assumptions considered inthat review included possible North Carolina retail electric base rates before 2006, except for future market prices for fuel and electricity, load growth, generating certain events that would have a significant financial impact on unit availability and future capacity additions in Dominion's market Dominion's electric utility operations. Fuel rates are still subject to capital expenditures, including those related to environmental change under the annual fuel cost adjustment proceedings. How-improvements, and decommissioning activities. Based on those ever, inApril 2004, the North Carolina Commission commenced an analyses, no recognition of plant impairments or contract losses was investigation into Dominion's North Carolina base rates and sub-appropriate at that time. Inresponse to future events resulting from sequently ordered Dominion to file a general rate case to show the development of a competitive market structure inVirginia and cause why its North Carolina base rates should not be reduced. The the expiration or termination of capped rates and wires charges, rate case was filed inSeptember 2004 and in February 2005, Dominion may have to reevaluate its utility generation assets for Dominion reached a tentative settlement with parties inthe case impairment and long-term power purchase contracts for potential that is subject to North Carolina Commission approval before losses. Assumptions about future market prices for electricity repre-becoming effective.

sent a critical factor that affects the results of such evaluations.

Dominion Transmission, Inc. (DTI) Rate Matter Since 1999, market prices for electricity have fluctuated significantly At the request of the Public Service Commission of the State of and will continue to be subject to volatility. Any such review inthe New York (PSCNY). DTI has engaged innegotiations with PSCNY future, which would be highly dependent on assumptions considered regarding the potential for a prospective reduction of DTI 's trans- appropriate at the time, could possibly result inthe recognition of portation and storage service rates to address concerns about the plant impairment or contract losses that would be material to level of DTI's earnings. As a result of these negotiations, DTI and Dominion's results of operations or its financial position.

PSCNY have reached an agreement inprinciple that establishes Changes to Cost Structure-In April 2004, the Governor of parameters for a potential rate settlement, which must be finalized Virginia signed into law amendments to the Virginia Restructuring by DTI and its customers. DTI is negotiating with its customers to Act and the Virginia fuel factor statute. The amendments extend reach a possible settlement agreement. The settlement parame- capped base rates until December 31, 2010, unless capped rates ters envision reduced rates to DTI's customers and a five-year are terminated earlier under the Virginia Restructuring Act. The moratorium on future changes to DTI's transportation and storage generation-related cash flows provided by the Virginia service rates. If DTI is able to reach an agreement with its Restructuring Act are intended to compensate Dominion for con-customers inthe first quarter of 2005, FERC approval of a filed tinuing to provide generation services and to allow Dominion to settlement could be obtained inthe second quarter of 2005. incur costs to restructure such operations during the transition period. As a result, during the transition period, Dominion's earn-Recovery of Stranded Costs ings may increase to the extent that it can reduce operating costs Stranded costs are those generation-related costs incurred or for its utility generation-related operations. Conversely, the same commitments made by utilities under cost-based regulation that risks affecting the recovery of Dominion's stranded costs, dis-may not reasonably be expected to be recovered ina competitive cussed above, may also adversely impact its cost structure during market. At December 31, 2004, Dominion's exposure to potentially the transition period. Accordingly, Dominion could realize the stranded costs included long-term power purchase contracts that negative economic impact of any such adverse event. Inaddition to could ultimately be determined to be above market; generating managing the cost of its generation-related operations, Dominion plants that could possibly become uneconomical in a deregulated may also seek opportunities to sell available electric energy and environment; and unfunded obligations for nuclear plant decom-capacity to customers beyond its electric utility service territory.

missioning and postretirement benefits not yet recognized in the Using cash flows from operations during the transition period, financial statements. Dominion believes capped electric retail Dominion may further alter its cost structure or choose to make rates and, where applicable, wires charges will provide an oppor-additional investment inits business.

tunity to recover a portion of its potentially stranded costs, The capped rates were derived from rates established as part of depending on market prices of electricity and other factors.

the 1998 Virginia rate settlement and do not provide for specific Recovery of Dominion's potentially stranded costs remains subject recovery of particular generation-related expenditures, except for D 2004 / Page 40

certain regulatory assets. To the extent that Dominion manages its rates for environmental expenditures related to regulated gas operations to reduce its overall operating costs below those levels transmission and distribution operations.

included in the capped rates, Dominion's earnings may increase.

Environmental Protection and MonitoringExpenditures Since the enactment of the Virginia Restructuring Act, Dominion has Dominion incurred approximately $132 million, $113 million and been reviewing its cost structure to identify opportunities to reduce

$123 million of expenses (including depreciation) during 2004, the annual operating expenses of its generation-related operations. 2003 and 2002, respectively, inconnection with environmental Inthe period 2001 through 2004, Dominion negotiated the termi-protection and monitoring activities, and expects these expenses nation of several long-term power purchase agreements that is to be approximately $203 million in2005 and $215 million in2006.

expected to reduce capacity payments in2005 by $179 million.

Inaddition, capital expenditures related to environmental controls Common Stock Dividend Increase were $94 million, $210 million and $280 million for 2004, 2003 and InJuly 2004, Dominion announced that its fourth-quarter dividend 2002, respectively. These expenditures are expected to be approx-payable December 20, 2004, would be increased by 2 cents per imately $123 million for 2005 and $207 million for 2006. The 2005 share to 66.5 cents per share. InFebruary 2005, the quarterly and 2006 amounts include planned expenditures for the newly dividend rate increased again from 66.5 cents per share to 67 acquired USGen electric generating facilities.

cents per share for an annual rate in2005 of $2.68 per share.

Clean AirAct Compliance Dominion's expected cash flow and earnings should enable it to The Clean Air Act requires Dominion to reduce its emissions of make future annual increases when its board of directors deems it sulfur dioxide (SO 2) and nitrogen oxide (NOx), which are gaseous financially prudent. Common stock dividends are declared on a by-products of fossil fuel combustion. The Clean Air Act's SO 2 and quarterly basis by the board of directors.

NOx reduction programs include:

Statoil ASA (Statoil) Agreement -

• The issuance of a limited number of SO 2 emission allowances.

InJune 2004, Dominion executed 20-year contracts with Statoil for Each allowance permits the emission of one ton of SO 2 into the the increased capacity planned for its Cove Point LNG facility and atmosphere. The allowances may be transacted with a third related gas transmission services. Under the terms of the agree- party; and ments, Statoil will purchase firm LNG tanker discharge services

• NOxemission limitations applicable during the ozone season months and related transportation service from Cove Point, as well as of May through September and on an annual average basis.

downstream firm transportation and storage services from DTI. Implementation of projects to comply with S02 and NOx limi-Plans call for increasing the Cove Point storage tank capacity to tations are ongoing and will be influenced by changes inthe regu-14.6 bcf and the plant's deliverability by 0.8 bcf per day to a total latory environment, availability of allowances, various state and of 1.8 bcf per day. To provide the transmission services, Dominion federal control programs and emission control technology. In also plans to expand its pipeline originating at Cove Point to response to these requirements, Dominion estimates it will make deliver more natural gas to interstate pipeline connections in the capital expenditures at its affected generating facilities (including Mid-Atlantic region as well as to build a pipeline and two com- the newly acquired electric generating facilities from USGen) of pressor stations incentral Pennsylvania. These projects are subject approximately $700 million during the period 2005 through 2009 to regulatory approval and are expected to be placed inservice in for SO 2 and NO, emission control equipment.

2008.

Other EPA Matters Environmental Matters In relation to a Notice of Violation received by Virginia Power in Dominion is subject to costs resulting from a number of federal, 2000 from the EPA, Dominion entered into a Consent Decree state and local laws and regulations designed to protect humah settlement in2003 and committed to improve air quality. Dominion health and the environment. These laws and regulations affect has already incurred certain capital expenditures for environmental future planning and existing operations. Theycan result in improvements at its coal-fired stations inVirginia and West increased capital, operating and other costs as a result of com- Virginia. Dominion continues to commit to additional measures in pliance, remediation, containment and monitoring obligations. its current financial plans and capital budget to satisfy the Historically, Dominion recovered such costs arising from regulated requirements of the Consent Decree.

electric operations through utility rates. However, to the extent that environmental costs are incurred inconnection with oper- Other ations regulated by the Virginia Commission, during the period As part of its review of Dominion's request related to the reis-ending December 31, 2010, inexcess of the level currently suance of a pollution discharge elimination permit for the Mill-included inthe Virginia jurisdictional electric retail rates, Domin- stone Power Station, the Connecticut Department of Environmental ion's results of operations will decrease. After that date, recovery Protection is evaluating the ecological impacts of the cooling through regulated rates may be sought for only those environ- water intake system. Until the permit is reissued, it is not possible mental costs related to regulated electric transmission and dis- to predict the financial impact that may result.

tribution operations and recovery, if any, through the generation In October 2003, the EPA and the Massachusetts Department of component of rates will be dependent upon the market price of Environmental Protection jointly issued a new National Pollutant electricity. Dominion also may seek recovery through regulated Discharge Elimination System permit for the USGen, Brayton Point Power Station. The new permit contained conditions that ineffect D 2004I/Page 41

require the installation of cooling towers to address concerns over WPS Resources Corporation (WPS), and Wisconsin Power & Light the withdrawal and discharge of cooling water. InNovember 2003, Company (WP&L), a subsidiary of Alliant Energy Corporation, to an appeal was filed with the EPA Environmental Appeals Board and purchase the Kewaunee nuclear power plant, located in the Division of Administrative LawAppeals inMassachusetts. Until northeastern Wisconsin. Under terms of the agreement, the the appeals process is completed, the outcome cannot be predicted. aggregate purchase price is $220 million incash, including $35 million for nuclear fuel. Dominion will sell 100%/o of the facility's Future Environmental Regulations output to WPS (59%) and WP&L (41 %)under a power purchase InJanuary 2004, the EPA proposed additional regulations addressing agreement that expires in2013. InNovember 2004, the Public pollution transport from electric generating plants as well as the Service Commission of Wisconsin voted to deny the sale. The regulation of mercury and nickel emissions. These regulatory transaction had received all other applicable regulatory approvals.

actions, inaddition to revised regulations to address regional haze, During January 2005, the commission granted Dominion's request are expected to be finalized in2005 and could require additional for a rehearing of the case. If approved by the commission, the reductions inemissions from Dominion's fossil fuel-fired generating transaction isexpected to close inthe first half of 2005. If, facilities. If these new emission reduction requirements are approved, Kewaunee would be included inthe Dominion Gen-imposed; significant additional expenditures may be required.

eration operating segment.

The U.S. Congress is considering various legislative proposals that would require generating facilities to comply with more strin- Restructuring of Contract with Non-Utility Generator gent air emissions standards. Emission reduction requirements In February 2005, Dominion paid $42 million in cash and assumed under consideration would be phased in under a variety of periods $62 million of debt in connection with the termination of a long-of up to 15 years. If these new proposals are adopted, additional term power purchase agreement and acquisition of the related significant expenditures may be required. generating facility used by Panda-Rosemary LP, a non-utility In 1997, the United States signed an international Protocol to generator, to provide electricity to Dominion. The transaction is limit man-made greenhouse emissions under the United Nations part of an ongoing program that seeks to achieve competitive cost Framework Convention on Climate Change. However, the Protocol structures at Dominion's utility generation business and is will not become binding unless approved by the U.S. Senate. expe6ted to reduce annual capacity payments by $18 million. The purchase price for the acquisition was allocated to the assets and Currently, the Bush Administration has indicated that it will not liabilities acquired based on their estimated fair values as of the pursue ratification of the Protocol and has set a voluntary goal of date of acquisition. Inconnection with the termination of the reducing the nation's greenhouse gas emission intensity by 18%

agreement, Dominion expects to record an after-tax charge of over the next 10 years. Several legislative proposals that include approximately $46 million.  :

provisions seeking to impose mandatory reductions of greenhouse gas emissions are under consideration in the United States Con- Long-Term Power Tolling Contract gress. Several Northeast states have already or are considering Inthe fourth quarter of 2004, Dominion recorded a $112 million the imposition of mandatory carbon dioxide (C0 2) reductions after-tax charge related to its interest in a long-term power tolling through the development of a regional cap-and-trade program. The contract with a 551 megawatt combined cycle facility located in cost of compliance with the Protocol or other mandatory green- Batesville, Mississippi. Dominion decided to divest its interest in house gas reduction obligations could be significant. Given the the long-term power tolling contract inconnection with its highly uncertain outcome and timing of future action, if any, by the reconsideration of the scope of certain activities of the Clearing-U.S. federal government on this issue, Dominion cannot predict the house, including those conducted on behalf of Dominion's business financial impact of future climate change actions on its operations segments, and its ongoing strategy to focus on business activities at this time. within the MAIN to Maine region. The charge is based on Domin-ion's evaluation of preliminary bids received from third parties, Other Matters reflecting the expected amount of consideration that would be USGen Power Stations required by a third party for its assumption of Dominion's interest In January 2005, Dominion closed on its purchase of three electric inthe contract in the first quarter of 2005.

power generation facilities from USGen for $642 million. The acquisition was part of a bankruptcy court-approved divestiture of Future Acquisitions generation assets by USGen. The plants include the 1,521-megawatt Brayton Point Station inSomerset, Massachusetts; the In2005, Dominion expects to focus on managing its existing assets 743-megawatt Salem Harbor Station in Salem, Massachusetts; rather than acquiring new assets through mergers or acquisitions.

and the 426- megawatt Manchester Street Station inProvidence, Exceptions would include acquiring a Midwest, Northeast or Mid-Rhode Island. These assets will be included inthe Dominion Atlantic nuclear station; replacing gas and oil reserves through Generation operating segment. Dominion did not acquire any of acquisitions if more cost effective than drilling; or continuing to buy the facilities' debt inthe transaction and plans to finance the out uneconomic long-term power purchase agreements.

acquisition with a combination of debt and equity.

Kewaunee Nuclear Power Plant During the fourth quarter of 2003, Dominion announced an agree-ment with Wisconsin Public Service Corporation, a subsidiary of D 2004/ Page 42

Market Rate Sensitive Instruments and Risk Management by recognition of the hedged transaction, such as revenue from sales.

Dominion's financial instruments, commodity contracts and related derivative financial instruments are exposed to potential losses Interest Rate Risk due to adverse changes in interest rates, equity security prices, Dominion manages its interest rate risk exposure predominantly by foreign currency exchange rates and commodity prices. Interest maintaining a balance of fixed and variable rate debt. Dominion rate risk generally is related to Dominion's outstanding debt. also enters into interest rate sensitive derivatives, including Commodity price risk is present in Dominion's electric operations, interest rate swaps and interest rate lock agreements. For financial.

gas and oil production and procurement operations, and energy instruments outstanding at December 31, 2004, a hypothetical marketing and trading operations due to the exposure to market 10% increase in market interest rates would decrease annual shifts in prices received and paid for natural gas, electricity and earnings by approximately $10 million. A hypothetical 10%

other commodities. Dominion uses derivative commodity contracts increase inmarket interest rates, as determined at December 31, to manage price risk exposures for these operations. Inaddition, 2003, would have resulted in a decrease inannual earnings of' Dominion is exposed to equity price risk through various portfolios approximately $6million.

of equity securities. Inaddition, Dominion, through subsidiaries, retains ownership, The following sensitivity analysis estimates the potential loss of mortgage investments, including subordinated bonds and of future earnings or fair value from market risk sensitive instru- interest-only residual assets retained from securitizations of ments over a selected time period due to a 10% unfavorable mortgage loans originated and purchased in prior years. Note 26 to change incommodity prices, interest rates and foreign currency the Consolidated Financial Statements discusses the impact of exchange rates. changes invalue of these investments.

Commodity Price Risk-Trading Activities Foreign Currency Exchange Risk As part of its strategy to market energy and to manage related Dominion's Canadian natural gas and oil exploration and pro-risks, Dominion manages a portfolio of commodity-based duction activities are relatively self-contained within Canada. As a derivative instruments held for trading purposes. These contracts result, Dominion's exposure to foreign currency exchange risk for are sensitive to changes in the prices of natural gas, electricity and these activities is limited primarily to the effects of translation certain other commodities. Dominion uses established policies and adjustments that arise from including that operation in its Con-procedures to manage the risks associated with these price solidated Financial Statements. Dominion's management monitors fluctuations and uses derivative instruments, such as futures, this exposure and believes it is not material. Inaddition, Dominion forwards, swaps and options, to mitigate risk by creating offsetting manages its foreign exchange risk exposure associated with market positions. anticipated future purchases of nuclear fuel processing services A hypothetical 10% unfavorable change incommodity prices denominated in foreign currencies by utilizing currency forward would have resulted ina decrease of approximately $23 million contracts. As a result of holding these contracts as hedges, Domin-and $56 million inthe fair value of Dominion's commodity-based ion's exposure to foreign currency risk is minimal. A hypothetical financial derivative instruments held for trading purposes as of 10% unfavorable change in relevant foreign exchange rates would December 31, 2004 and 2003, respectively. have resulted ina decrease of approximately $13 million and $19 million in the fair value of currency forward contracts held by Commodity Price Risk-Non-Trading Activities Dominion at December 31, 2004 and 2003, respectively.

Dominion manages the price risk associated with purchases and sales of natural gas, oil and electricity by using derivative Investment Price Risk commodity instruments including futures, forwards, options and Dominion is subject to investment price risk due to marketable swaps. For sensitivity analysis purposes, the fair value of Domin- securities held as investments indecommissioning trust funds. In ion's non-trading derivative commodity instruments is determined accordance with current accounting standards, these marketable based on models that consider the market prices of commodities in securities are reported on the Consolidated Balance Sheets at fair future periods, the volatility of the market prices ineach period, as value. Dominion recognized a net realized gain (net of investment well as the time value factors of the derivative instruments. income) on nuclear decommissioning trust investments of $51 Market prices and volatility are principally determined based on million in2004 and a net realized loss (net of investment income) quoted prices on the futures exchange. A hypothetical 10% of $10 million in2003. Dominion recorded, in AOCI, net unrealized unfavorable change inmarket prices of Dominion's non-trading gains on decommissioning trust investments of $84 million and commodity-based financial derivative instruments would have $263 million in 2004 and 2003, respectively.

resulted in a decrease in fair value of approximately $576 million Dominion also sponsors employee pension and other postretire-and $424 million as of December 31, 2004 and December 31,2003, ment benefit plans that hold investments intrusts to fund benefit respectively. payments. To the extent that the values of investments held in The impact of a change in energy commodity prices on Domin- these trusts decline, the effect will be reflected inDominion's ion's non-trading derivative commodity-based financial derivative recognition of the periodic cost of such employee benefit plans and instruments at a point intime is not necessarily representative of the determination of the amount of cash to be contributed to the the results that will be realized when such contracts are ultimately employee benefit plans. Dominion's pension plans experienced net settled. Net losses from derivative commodity instruments used for realized and unrealized gains of $453 million and $627 million in hedging purposes, to the extent realized, are substantially offset 2004 and 2003, respectively.

D 2004 / Page 43

Risk Management Policies environmental legislation and associated regulations. Manage-Dominion has operating procedures in place that are administered ment believes the necessary approvals have been obtained for by experienced management to help ensure that proper internal Dominion's existing operations and that its business is conducted controls are maintained. Inaddition, Dominion has established an inaccordance with applicable laws. However, new laws or regu-independent function at the corporate level to monitor compliance lations. or the revision or reinterpretation of existing laws or regu-with the risk management policies of all subsidiaries. Dominion lations, may require Dominion to incur additional expenses.

maintains credit policies that include the evaluation of a pro- Costs of environmental compliance, liabilities and liti-spective counterparty's financial condition, collateral requirements gation could exceed Dominion's estimates which could where deemed necessary, and the use of standardized agreements adversely affect its results of operations. Compliance with that facilitate the netting of cash flows associated with a single federal, state and local environmental laws and regulations may counterparty. In addition, Dominion also monitors the financial result inincreased capital, operating and other costs, including condition of existing counterparties on an ongoing basis. Based on remediation and containment expenses and monitoring obliga-credit policies and the December 31, 2004 provision for credit tions. Inaddition, Dominion may be a responsible party for losses, management believes that it is unlikely that a material environmental clean-up at a site identified by a regulatory body.

adverse effect on its financial position, results of operations or Management cannot predict with certainty the amount and timing cash flows would occur as a result of counterparty non- of all future expenditures related to environmental matters.

performance. because of the difficulty of estimating clean-up and compliance costs, and the possibility that changes will be made to the current environmental laws and regulations. There isalso uncertainty in quantifying liabilities under environmental laws that impose joint Risk Factors and Cautionary Statements That May Affect and several liability on all potentially responsible parties.

Future Results Dominion is exposed to cost-recovery shortfalls because Factors that may cause actual results to differ materially from of capped base rates and amendments to the fuel factor those indicated inany forward-looking statement include weather statute ineffect inVirginia for its regulated electric utility.

conditions; governmental regulations; cost of environmental com- Under the Virginia Restructuring Act, as amended inApril 2004, pliance; inherent risk inthe operation of nuclear facilities; fluctua- Dominion's base rates (excluding, generally, a fuel factor with tions in energy-related commodities prices and the effect these limited adjustment provisions, and certain other allowable could have on Dominion's earnings, liquidity position and the adjustments) remain unchanged until December 31, 2010 unless underlying value of its assets; trading counterparty credit risk; modified or terminated consistent with the Virginia Restructuring capital market conditions, including price risk due to marketable Act. Although the Virginia Restructuring Act allows for the securities held as investments intrusts and benefit plans; fluctua- recovery of certain generation-related costs during the capped tions ininterest rates; changes in rating agency requirements or rates periods, Dominion remains exposed to numerous risks of ratings; changes inaccounting standards; collective bargaining cost-recovery shortfalls. These include exposure to potentially agreements and labor negotiations; the risks of operating busi- stranded costs, fLture environmental compliance requirements, tax nesses inregulated industries that are subject to changing regu- law changes, costs related to hurricanes or other weather events, latory structures; changes to regulated gas and electric rates inflation, the cost of obtaining replacement power during recovered by Dominion; receipt of approvals for and the timing of unplanned plant outages and increased capital costs. In addition, the closing dates for pending acquisitions; realization of expected under the 2004 amendments to the Virginia fuel factor statute, business interruption insurance proceeds; the transfer of control Dominion's current Virginia fuel factor provisions are locked-in over electric transmission facilities to a regional transmission until the earlier of July 1,2007 or the termination of capped rates organization; board approval of future dividends; political and by order of the Virginia State Corporation Commission.

economic conditions (including inflation and deflation); and com- The amendments provide for a one-time adjustment cf Domin-pleting the divestiture of investments held by DCI. Other more ion's fuel factor, effective July 1,2007 through December 31, specific risk factors are as follows: 2010, with no adjustment for previously incurred over-recovery or Dominion's operations are weather sensitive. Dominion's under-recovery, thus eliminating deferred fuel accounting. As a results of operations can be affected by changes in the weather. result of the locked-in fuel factor and the uncertainty of what the Weather conditions directly influence the demand for electricity one-time adjustment will be, Dominion is exposed to fuel price and natural gas and affect the price of energy commodities. n risk. This risk includes exposure to increased costs of fuel, addition, severe weather, including hurricanes, winter storms and including the energy portion of certain purchased power costs.

droughts, can be destructive, causing outages, production delays Under the Virginia Restructuring Act, the generation and property damage that require Dominion to incur additional portion of Dominion's electric utilityoperations is open to expenses. competition and resulting uncertainty. Under the Virginia Dominion is subject to complex government regulation Restructuring Act, the generation portion of Dominion's electric that could adversely affect its operations. Dominion's oper- utility operations inVirginia is open to competition and is no longer ations are subject to extensive federal, state and local regulation subject to cost-based regulation. To date, the competitive market and may require numerous permits, approvals and certificates from has been slow to develop. Consequently, it isdifficult to predict various governmental agencies. Dominion must also comply with the pace at which the competitive environment will evolve and the D 2004/ Page 44

extent to which Dominion will face increased competition and be Dominion is exposed to market risks beyond its control able to operate profitably within this competitive environment. in its energy clearinghouse operations which could Dominion's merchant power business is operating in a adversely affect its results of operations and future growth.

challenging market which could adversely affect its results Dominion's energy clearinghouse and risk management operations of operations and future growth. The success of Dominion's are subject to multiple market risks including market liquidity, approximately 9,700-megawatt merchant power business depends counterparty credit strength and price volatility. Many industry upon favorable market conditions as well as its ability to find participants have experienced severe business downturns resulting buyers willing to enter into power purchase agreements at prices insome companies exiting or curtailing their participation inthe sufficient to cover operating costs. Dominion attempts to manage energy trading markets. This has led to a reduction inthe number these risks by entering into both short-term and long-term fixed . of trading partners and lower industry trading revenues. Declining price sales and purchase contracts. However, depressed spot and creditworthiness of some of Dominion's trading counterparties forward wholesale power prices, high fuel and commodity costs may limit the level of its trading activities with these parties and and excess capacity inthe industry could result inlower than increase the risk that these parties may not perform under a con-expected revenues inDominion's merchant power business. tract. - . I . .

There are inherent risks inthe operation of nuclear Dominion's exploration and production business is facilities. Dominion operates nuclear facilities that are subject to dependent on factors that cannot be predicted or controlled inherent risks. These include the threat of terrorist attack and and that could damage facilities, disrupt production or ability to dispose of spent nuclear fuel, the disposal of which is reduce the book value of its assets. Factors that may affect subject to complex federal and state regulatory constraints. These Dominion's financial results include weather that damages or risks also include the cost of and Dominion's ability to maintain causes the shutdown of its gas and oil producing facilities, fluctua-adequate reserves for decommissioning, costs of plant main- tions in natural gas and crude oil prices, results of future drilling tenance and exposure to potential liabilities arising out of the and well completion activities and Dominion's ability to acquire operation of these facilities. Dominion maintains decommissioning additional land positions in competitive lease areas, as well as trusts and external insurance coverage to manage the financial inherent operational risks that could disrupt production.

exposure to these risks. However, it is possible that costs arising Short-term market declines inthe prices of natural gas and oil from claims could exceed the amount of any insurance coverage. could adversely affect Dominion's financial results by causing a The use of derivative instruments could result infinan- permanent write-down of its natural gas and oil properties as cial losses and liquidity constraints. Dominion uses derivative required by the full cost method of accounting. Under the full cost instruments, including futures, forwards, options and swaps, to method, all direct costs of property acquisition, exploration and manage its commodity and financial market risks. In addition, development activities are capitalized. If net capitalized costs Dominion purchases and sells commodity-based contracts inthe exceed the present value of estimated future net revenues based natural gas, electricity and oil markets for trading purposes. Inthe on hedge-adjusted period-end prices from the production of proved future, Dominion could recognize financial losses on these con- gas and oil reserves (the ceiling test) in a given country at the end tracts as a result of volatility inthe market values of the underlying of any quarterly period, then a permanent write-down of the assets commodities or if a counterparty fails to perform under a contract. must be recognized inthat period.

Inthe absence of actively quoted market prices and pricing An inability to access financial markets could affect the information from external sources, the valuation of these contracts execution Gf Dominion's business plan. Dominion and its involves management's judgment or use of estimates. As a result, Virginia Power and CNG subsidiaries rely on access to bcth short-changes inthe underlying assumptions or use of alternative valu-. term money markets and longer-term capital markets as a ation methods could affect the reported fair value of these - significant source of liquidity for capital requirements not satisfied contracts. by the cash flows from its operations. Management believes that Inaddition, Dominicn uses financial derivatives to hedge future Dominion and its subsidiaries will maintain sufficient access to sales of its gas and oil production. These hedge arrangements these firar-cial markets based upon current credit ratings. How-generally include margin requirements that require Dominion to ever, certain disruptions outside of Dominion's control may deposit funds or post letters of credit with counterparties to cover increase its cost of borrowing or restrict its ability to access one or the fair value of covered contracts inexcess of agreed upon credit more financial markets. Such disruptions could include an limits. When commodity prices rise to levels substantially higher economic downturn, the bankruptcy of an unrelated energy than the levels where it has hedged future sales, Dominion may be company or changes to Dominion's credit ratings. Restrictions on required to use a material portion of its available liquidity to cover Dominion's ability to access financial markets may affect its ability these margin requirements. Insome circumstances, this could have to execute its business plan as scheduled.

a compounding effect on Dominion's financial liquidity and results.

For additional information concerning derivatives and commodity-based trading contracts, see Market Rate Sensitive Instruments andRisk Managementand Notes 2 and 8 to the Consolidated Financial Statements.

D 2004 I Page 45

1.

Changing rating agency requirements could negatively affect Dominion's growth and business strategy. As of February 1,2005, Dominion's senior unsecured debt is rated BBB+.

negative outlook, by Standard & Poor's and Baal, stable outlook, by Moody's. Both agencies have implemented more stringent applications of the financial requirements for various ratings lev-els. In order to maintain its current credit ratings in light of these or future new requirements, Dominion may find it necessary to take steps or change its business plans inways that may adversely affect its growth and earnings per share. A reduction inDominion's credit ratings or the credit ratings of its Virginia Power and CNG subsidiaries by either Standard & Poor's or Moody's could increase Dominion's borrowing costs and adversely affect operating results and could require it to post additional margin inconnection with some of its trading and marketing activities.

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

Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse effect on the operations of Dominion.

Implementation of Dominion's growth strategy isdependent on its ability to recruit, retain and motivate employees. Competition for skilled employees in some areas ishigh and the inability to retain and attract these employees could adversely affect Dominion's business and future financial condition.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk See Risk Factors and Cautionary Statements That MayAffect Future Results and Market Rate Sensitive Instruments and Risk Management inItem 7.Management's Discussion and Analysis of Financial Condition and Results of Operations.

D 20041 Page 46

Item 8. Financial Statements and Supplementary Data Index Page No.

Management's Annual Report on Internal Control over Financial Reporting ................... ............ . 48 Reports of Independent Registered Public Accounting Firm .49 Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002 .: 51 Consolidated Balance Sheets at December 31, 2004 and 2003 .52 Consolidated Statements of Common Shareholders' Equity and Comprehensive Income at December 31. 2004. 2003 and 2002 and for the years then ended ...................  ;.:.. 54 Consolidated Statements of Cash Flows for the years ended December 31, 2004. 2003 and 2002 ..... ............... 55 Notes to Consolidated Financial Statements ......................... ....... ' 55.........

56 D 20041 Page 47

1.

Management's Annual Report on Internal Control over Financial Reporting Management of Dominion Resources, Inc. (Dominion) understands and accepts responsibility for its financial statements and related dis-closures and the effectiveness of internal control over financial reporting (internal control). Dominion continuously strives to identify oppor-tunities to enhance the effectiveness and efficiency of internal control, just as it does throughout all aspects of its business.

Management maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that Dominion's and its subsidiaries' assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.

The Audit Committee of the Board of Directors of Dominion, composed entirely of independent directors, meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss auditing, internal control, and financial reporting matters of Dominion and to ensure that each is properly discharging its responsibilities. Both the independent registered public accounting firm and the internal auditors periodically meet alone with the Audit Committee and have free access to the Committee at any time.

SEC rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 require Dominion's 2004 Annual Report to contain a manage-ment's report and a report of the independent registered public accounting firm regarding the effectiveness of internal control. As a basis for management's report, Dominion tested and evaluated the design and operating effectiveness of internal controls. Based on its assessment as of December 31, 2004, Dominion makes the following assertion:

Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion.

There are inherent limitations inthe effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial state:

ment preparation. Further, because of changes inconditions, the effectiveness of internal control may vary over time.

On December 31, 2003, Dominion adopted Financial Accounting Standards Board Interpretation No. 46 (revised December 2003), Con-solidation of Variable Interest Entities, for its interests inspecial purpose entities, referred to as SPEs. As a result, Dominion has included in its consolidated financial statements certain SPEs. The Consolidated Balance Sheet, as of December 31, 2004, reflects $621 million of net property, plant and equipment and deferred charges and $688 million of related debt attributable to these SPEs. As these SPEs are owned by unrelated parties, Dominion does not have the authority to dictate or modify, and therefore could not assess the internal controls inplace at these entities. Management's conclusion regarding the effectiveness of Dominion's internal control does not extend to the internal controls of these SPEs.

Management evaluated Dominion's internal control over financial reporting as of December 31, 2004. This assessment was based on criteria for effective internal control over financial reporting described inInternal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Dominion maintained effec-tive internal control over financial reporting as of December 31, 2004.

The independent registered public accounting firm that audited the financial statements has issued an attestation report on Dominion's assessment of the internal control over financial reporting.

February 28, 2005 D 2004 1Page 48

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Shareholders and Board of Directors of Dominion Resources, Inc.

Richmond, Virginia We have audited the accompanying consolidated balance sheets of Dominion Resources, Inc. and subsidiaries (the "Company") as of December 31, 2004 and 2003, and the related consolidated statements of income, common shareholders' 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 isto 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 examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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.

Inour opinion, such consolidated financial statements present fairly, inall material respects, the financial position of Dominion Resources, Inc. and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the consolidated financial statements, in2003 the Company changed its methods of accounting to adopt new accounting standards for: asset retirement obligations, contracts involved in energy trading, derivative contracts not held for trading pur-poses, derivative contracts with a price adjustment feature, the consolidation of variable interest entities, and guarantees.

We have also audited, inaccordance with the standards of the Public Company Accounting Oversight Board (United States), the effective-ness of the Company's internal control over financial reporting as of December 31, 2004, based on criteria established inInternal Control-IntegratedFrameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28.

2005, expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

/s/ Deloitte & Touche LLP Richmond, Virginia February 28, 2005 D 2004/ Page 49

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Shareholders and Board of Directors of Dominion Resources, Inc.

Richmond, Virginia We have audited management's assessment, included inparagraphs 5-9 of the accompanying Management's Annual Report on Internal Control over Financial Reporting, that Dominion Resources. Inc. and subsidiaries (the "Company') maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in Management's Annual Report on Internal Control over Financial Reporting, management excluded from their assessment the internal control over financial reporting at certain special purpose entities consolidated under Financial Accounting Standards Board Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities. The Company's Consolidated Balance Sheet, as of December 31, 2004, reflects $621 million of net property, plant and equipment and deferred charges and $688 million of related debt attributable to these special purpose entities. As these special purpose entities are owned by unrelated parties, the Company does not have the authority to dictate or modify, and therefore could not assess the internal controls inplace at these entities. Accordingly, our audit did not include the internal control over financial reporting at those special purpose entities. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility isto express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit inaccordance with the standards of the Public Company Accounting Oversight Board (United Statesi. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal execu-tive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial state-ments for external purposes inaccordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1)pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2)provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only inaccordance with authorizations of management and directors of the company; and (3)provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper manage-ment override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes inconditions, or that the degree of compliance with the policies or procedures may deteriorate.

Inour opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairlystated, in all material respects, based on the criteria established inInternal Control-lntegratedFramewlorkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Also inour opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, inaccordance with the standards of the Public Company Accounting Oversight Board (United States), the con-solidated financial statements and financial statement schedule as of and for the year ended December 31, 2004 of the Company and our reports dated February 28, 2005, expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/ Deloitte & Touche LLP Richmond, Virginia February 28, 2005 D 2004 IPage 50

Consolidated Statements of Income Year Ended December 31 2304 2003 2002 (millions, except per share amounts)

Operating Revenue $13,972 $12,078 $10,218 Operating Expenses Electric fuel and energy purchases, net 2162 1,667 1,447 Purchased electric capacity 587 607 691 Purchased gas. net 2,927 2,175 1,159 Liquids, pipeline capacity and other purchases 1,007 468 159 Other operations and maintenance 2,748 2,908 2,190 Depreciation, depletion and amortization 1,305 1,216 1,258 Other taxes 519 476 429 Total operating expenses 11255 9,517 7.333 Income from operations 2,717 2,561 2,885 Other income (loss) 186 (40) 103 Interest and related charges:

Interest expense 811 849 826.

Interest expense-junior subordinated notes payable to affiliated trusts 112 - -

Distributions-mandatorily redeemable trust preferred securities - 111 103 Subsidiary preferred dividends 16 15 16 Total interest and related charges 939 975 945 Income before income taxes 1,964 1,546 2,043 Income tax expense 700 597 681 Income from continuing operations before cumulative effect of changes inaccounting principles 1.264 949 1,362 Loss from discontinued operations (net of income tax benefit of $4and expense of $15, in 2004 and 2003, respectively) . (15) (642)

Cumulative effect of changes in accounting principles (net of income taxes of $7) - 11 -

Net Income $ 1,249 $ 318 $ 1,362 Earnings Per Common Share-Basic:

Income from continuing operations before cumulative effect of changes in accounting principles $ 3.84 $ 2.99 $ 4.85 Loss from discontinued operations - (0.04) 12.02) -

Cumulative effect of changes in accounting principles, - .03 -

Net income $ 3.80 $ 1.00 $ 4.85 Earnings Per Common Share-Diluted:

Income from continuing operations before cumulative effect of changes in accounting principles $ 3.82 $ 2.98 $ 4.82 Loss from discontinued operations (0.04) (2.01) -

Cumulative effect of changes in accounting principles - .03 Net income $ 3.78 $ 1.00 $ 4.82 Dividends paid per common share $ 2.60 $ 2.58 $ 2.58 The accompanying notes are an integral part of the Consolidated Financial Statements.

D 2004/ Page 51

Consolidated Balance Sheets At December 31, 2004 2003 (millions)

ASSETS Current Assets Cash and cash equivalents $ 389 $ 126 Customer accounts receivable (net of allowance of $43 and $51) 2,585 2,308 Other accounts receivable 320 828 Inventories:

Materials and supplies 328 296 Fossil fuel 180 154 Gas stored 385 420 Derivative assets 1,713 1,436 Deferred income taxes 594 240 Prepayments 157 202 Other 471 531 Total current assets 7,122 6,541 Investments Available for sale securities 335 413 Nuclear decommissioning trust funds 2,023 1,872 Other 810 802 Total investments 3,168 3,087 Property, Plant and Equipment Property, plant and equipment 38,663 37,107 Accumulated depreciation, depletion and amortization (11,947) (11,257)

Total property, plant and equipment, net 26,716 25,850 Deferred Charges and Other Assets Goodwill, net 4,298 4,300 Regulatory assets 788 832 Prepaid pension cost 1,947 1.939 Derivative assets 705 402 Other 702 595 Total deferred charges and other assets 8,440 8,068 Total assets $ 45,446 $43,546 D 20041 Page 52

At December31. 2004 2003 (millions)

LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities Securities due within one year $ 1,368 $ 1,252 Short-term debt 573 1,452 Accounts payable. trade 1,984 1,929 Accrued interest, payroll and taxes 578 619 Derivative liabilities .2,858 . 2,082 Other 695 . 750 Total current liabilities 8,056 8,084 Long-Term Debt Long-term debt 14,078 14,336 Junior subordinated notes payable to affiliated trusts 1,429 1,440 Total long-term debt 15,507 15,776 Deferred Credits and Other Liabilities Deferred income taxes 5,424 4,614 Deferred investment tax credits 75 92 Asset retirement obligations 1,705 1,651 Derivative liabilities 1,583 1,185 Regulatory liabilities 610 ' 587 Other 803 762 Total deferred credits and other liabilities 10,200 8,891 Total liabilities 33,763 32,751 Commitments and Contingencies (see Note 22) - -

Subsidiary Preferred Stock Not Subject To Mandatory Redemption 257 257 Common Shareholders' Equity Common stock-no par11) 10,888 10,052 Other paid-in capital 92 61 Retained earnings 1,442 1,054 Accumulated other comprehensive loss (996) (629]

Total common shareholders' equity 11,426 10,538 Total liabilities and shareholders' equity $45,446 $43,546 11)500 million shares authorized. 340 million shares and 325 million shares outstanding at December 31, 2004 and December 31, 2003, respectively.

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

D 2004/ Page 53

Consolidated Statements of Common Shareholders' Equity and Comprehensive Income

.Accumulated Other Other Common Stock Paid-In Retained Comprehensive Shares Amount Capital Earnings Income (Loss), Total (millions)

Balance at December 31. 2001 265 $ 7,129 $28 $ 922 $ 289 $ 8,368 Comprehensive income:

Net income 1,362 1,362 Net deferred losses on derivatives-hedging activities, net of $345 tax benefit (663) (663)

Unrealized losses on investment securities, net of $41 tax benefit (68) (68)

Foreign currency translation adjustments 6 6 Minimum pension liability adjustment. net of $1tax benefit 12) (2)

Amounts reclassified to net income:.

Net derivative gains-hedging activities, net of $4tax expense - 81 (8)

Total comprehensive income . 1,362 1735) 627 Issuance of stock-public offering 38 1,712 1,712 Issuance of stock-employee and direct stock purchase plans 3 199 199 Stock awards and stock options exercised (net of change in unearned compensation) 3 113 113 Stock repurchase and retirement (1) (66) (66)

Accrued contract payments-equity-linked securities (36)  ; (36)

Tax benefit from stock awards and stock options exercised 21 21 Dividends and other adjustments (2) (723) (725)

Balance at December 31, 2002 308 9,051 47 1,561 (446) 10,213 Comprehensive income:

Net income 318 318 Net deferred derivative losses-hedging activities, net of $479 tax benefit (791) (791)

Unrealized gains on investment securities. net of $78 tax expense 112 112 Foreign currency translation adjustments 68 68 Amounts reclassified to net income:

Net realized losses on investment securities, net of $29 tax benefit 49 49 Net losses on derivatives-hedging activities, net of $225 tax benefit 379 379 Total comprehensive income 318 1183) 135 Issuance of stock-public offering 11 683 683 Issuance of stock-employee and direct stock purchase plans 3 206 206 Stock awards and stock options exercised (net of change in unearned compensation) 3 112 112 Tax benefit from stock awards and stock options exercised 14 14 Dividends (825) (825)

Balance at December 31,2003 325 10,052 61 1,054 (629) 10,538 Comprehensive income:

Net income 1,249 . . 1,249 Net deferred derivative losses-hedging activities, net of $632 tax benefit (1,118) (1,1I8)

Unrealized gains, on investment securities, net of $18 tax expense 37 37 Foreign currency translation adjustments 30 30 Amounts reclassified to net income:

Net realized losses on investment securities, net of $12 tax benefit 23 23 Net losses on derivatives-hedging activities, net of $407 tax benefit 705 705 Foreign currency translation adjustments") (44) (44)

Total comprehensive income 1,249 (367) 882 Issuance of stock-equity-linked securities 7 413 413 Issuance of stock-employee and direct stock purchase plans 3 206 206 Stock awards and stock options exercised (net of change in unearned compensation) 5 223 223 Cash settlement-forward equity transaction (6) (6)

Tax benefit from stock awards and stock options exercised 31 31 Dividends (861) (861)

Balance at December 31,2004 340 $10,888 $92 $1,442 S (996) $11,426 (1)Reclassified to earnings due to the sale of CNG International investments.

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

D 20041 Page 54

Consolidated Statements of Cash Flows Year Ended December 31, 2004 2003 2002 (millionsl Operating Activities Net income S 1,249 $ 318 $ 1,362 Adjustments to reconcile net income to net cash from operating activities:

Impairment of telecommunications assets - 566 -

DCI impairment losses 72 85 13 Impairment (recovery) of CNG's international assets (18) 84 Net unrealized gains on energy trading contracts (113) . (54) .15)

Depreciation, depletion and amortization . 1,433 1,334 ,1,379 Deferred income taxes and investment tax credits, net . 554 . 452 .714 Other adjustments for non-cash items 9 . 22 34 Changes in:

Accounts receivable (288) (507) (442)

Inventories .- (24) (234) (55)

Deferred fuel and purchased gas costs, net 89 (244) (143)

Prepaid pension cost (8) (229) 1198)

Accounts payable, trade 55 372 .155 Accrued interest, payroll and taxes - (9) 42 58 Deferred revenue (223) (43)

Margin deposit assets and liabilities (6) (18) (186)

Other operating assets and liabilities 67 409 (238)

Net cash provided by operating activities 2839 2,355 2,443 Investing Activities Plant construction and other property additions (1,451) (2,138) (1,339)

Additions to gas and oil properties, including acquisitions (1,299) (1,300) (1,489)

Proceeds from sales of gas and oil properties 729 305 15 Acquisition of businesses - - (410)

Proceeds from sales of loans and securities 466 912 572 Purchases of securities (490) (777) (462)

Escrow release (deposit) for debt refunding - 500 (500)

Purchase of Dominion Fiber Ventures senior notes - (633) -

Advances to lessor for project under construction (132) (385) (240)

Reimbursement from lessor for project under construction 806 -

Other 115 143 (107)

Net cash used in investing activities (1,256) (3,373) (3,960)

Financing Activities Issuance (repayment) of short-term debt, net (879) 259 (666)

Issuance of long-term debt and preferred stock 877 3,393 2,434 Repayment of long-term debt and preferred stock (1,283) (2,922) (1,904)

Issuance of preferred securities by subsidiary trusts - - 400 Repayment of preferred securities of subsidiary trusts - - (135)

Issuance of common stock 839 990 2,020 Repurchase of common stock - - (66)

Common dividend payments (861) f825) (723)

Other (13) (42) (43)

Net cash provided by (used in)financing activities (1,320) 853 1,317 Increase (decrease) in cash and cash equivalents 263 (165) (195)

Cash and cash equivalents at beginning of period 126 291 486 Cash and cash equivalents at end of period S 389 $ 126 $ 291 Supplemental Cash Flow Information:

Cash paid (received) during the year for:

Interest and related charges, excluding capitalized amounts S 926 $ 941 $ 912 Income taxes (8) (32) (8)

Noncash transactions from investing and financing activities:

Assumption of debt related to acquisitions of non-utility generating facilities 213 - -

Proceeds held in escrow from sale of gas and oil properties 156 - -

Exchange of debt securities 325 500 567 The accompanying notes are an integral part of the Consolidated Financial Statements.

D 20041 Page 55

Notes to Consolidated Financial Statements 1.Nature of Operations The term "Dominion' is used throughout this report and, depending on the context of its use, may represent any of the Dominion Resources, Inc. (Dominion) is a holding company head-following: the legal entity, Dominion Resources, Inc., one of quartered inRichmond, Virginia. Its principal subsidiaries are Dominion Resources, Inc.'s consolidated subsidiaries or the Virginia Electric and Power Company (Virginia Power), Con-entirety of Dominion Resources, Inc. and its consolidated sub-solidated Natural Gas Company (CNG) and Dominion Energy, Inc.

sidiaries.

(DEl). Dominion and CNG are registered public utility holding companies under the Public Utility Holding Company Act of 1935 (1935 Act).

Virginia Power is a regulated public utility that generates, 2. Significant Accounting Policies transmits and distributes electricity within an area of approx- General imately 30,000-square-miles inVirginia and northeastern North Dominion makes certain estimates and assumptions in preparing Carolina. Virginia Power serves approximately 2.3 million retail its Consolidated Financial Statements in accordance with customer accounts, including governmental agencies and whole- accounting principles generally accepted in the United States of sale customers such as rural electric cooperatives, municipalities, America (generally accepted accounting principles). These esti-power marketers and other utilities. Virginia Power has trading mates and assumptions affect the reported amounts of assets and relationships beyond the geographic limits of its retail service liabilities, the disclosure of contingent assets and liabilities at the territory and buys and sells natural gas, electricity and other date of the financial statements and the reported amounts of energy-related commodities. revenues and expenses for the periods presented. Actual results CNG operates inall phases of the natural gas business, may differ from those estimates.

explores for and produces gas and oil and provides a variety of The Consolidated Financial Statements include, after energy marketing services. Its regulated gas distribution sub- eliminating intercompany transactions and balances, the accounts sidiaries serve approximately 1.7 million residential, commercial of Dominion and all majority-owned subsidiaries, and those and industrial gas sales and transportation customer accounts in variable interest entities (VIEs) where Dominion has been Ohio, Pennsylvania and West Virginia and its nonregulated retail determined to be the primary beneficiary.

energy marketing businesses serve approximately 1.2 million Certain amounts inthe 2003 and 2002 Consolidated Financial residential and commercial customer accounts inthe Northeast, Statements and footnotes have been reclassified to conform to the Mid-Atlantic and Midwest. CNG operates an interstate gas trans- 2004 presentation.

mission pipeline system inthe Midwest, Mid-Atlantic states and Operating Revenue the Northeast and a liquefied natural gas (LNG) import and storage Operating revenue is recorded on the basis of services rendered, facility in Maryland. Its producer services operations involve the commodities delivered or contracts settled and includes amounts aggregation of natural gas supply and related wholesale activities.

yet to be billed to customers. Dominion's customer accounts CNG's exploration and production operations are located inseveral receivable at December 31, 2004 and 2003 included $384 million major gas and oil producing basins inthe United States, both.

onshore and offshore. and $342 million, respectively, of accrued unbilled revenue based DEI is involved in merchant generation, energy trading and on estimated amounts of electric energy or natural gas delivered marketing and natural gas and oil exploration and production. but not yet billed to its utility customers. Dominion estimates Dominion has substantially exited the core operating busi- unbilled utility revenue based on historical usage, applicable nesses of Dominion Capital, Inc. (DCI), as required by the Secu- customer rates, weather factors and, for electric customers, total rities and Exchange Commission (SEC) under the 1935 Act. daily electric generation supplied after adjusting for estimated Currently, Dominion is required to divest all remaining DCI holdings losses of energy during transmission.

by January 2006. DCl's primary business was financial services, The primary types of sales and service activities reported as including loan administration, commercial lending and residential operating revenue include:

mortgage lending.

• Regulated electric sales consist primarily of state-regulated Dominion manages its daily operations through four primary retail electric sales and federally regulated wholesale electric operating segments: Dominion Generation, Dominion Energy, sales and electric transmission services subject to cost-of-Dominion Delivery and Dominion Exploration & Production. In service rate regulation; addition, Dominion reports a Corporate and Other segment that

• Regulated gas sales consist primarily of state-regulated retail includes the operations of Dominion's corporate, service company natural gas sales and related distribution services; and other operations (including unallocated debt), DCI and the net

• Nonregulated electric sales consist primarily of sales of impact of Dominion's discontinued telecommunications operations electricity from utility and merchant generation facilities at that were sold in May 2004. Assets remain wholly owned by its market-based rates, sales of electricity to residential and legal subsidiaries. commercial customers at contracted fixed prices and market-based rates and electric trading revenue; D 20041 Page 56

Notes to Consolidated Financial Statements, Continued

• Nonregulated gas sales consist primarily of sales of natural gas basis in Dominion's Consolidated Statements of Income that could at market-based rates, sales of gas purchased from third be impacted by further EITF deliberations inthis area are summar-parties and gas trading revenue; ized below. --;

• Gas transportation andstorageconsists primarily of regulated Year Ended December 31, 2004 2003 2002 sales of gathering, transmission, distribution and storage services. Imillions)

Also included are regulated gas distribution charges to retail Sale activity included inoperating revenue $290 $181 $164 distribution service customers opting for alternate suppliers; Purchase activity included inoperating expensestll 271 163 147

• Gas and oilproduction consists primarily of sales of natural gas, oil and condensate produced by Dominion including the recognition of Ill Included inLiquids, pipeline capacity and other purchases revenue previously deferred inconnection with the volumetric Electric Fuel, Purchased Energy and Purchased Gas-production payment (VPP) transactions described inNote 12. Gas Deferred Costs and oil production revenue is reported net of royalties; and Where permitted by regulatory authorities, the differences

• Otherrevenue consists primarily of miscellaneous service revenue between actual electric fuel; purchased energy and purchased gas from electric and gas distribution operations; sales of coal and expenses and the levels of recovery for these expenses incurrent extracted products; gas and oil processing; gas transmission rates are deferred and matched against recoveries in future peri-pipeline capacity release; sales of emissions credits; business ods. The deferral of costs or recovery of fuel rate revenue in excess interruption insurance revenue associated with delayed gas and oil of current period expenses is recognized as a regulatory asset or production caused by Hurricane Ivan; and sales activity related to liability.

agreements used to facilitate the marketing of oil production. As for electric fuel and purchased energy expenses, effective See Derivative Instruments below for a discussion of January 1,2004, Dominion's fuel factor provisions for its Virginia accounting changes, effective January 1,2003 and October 1, retail customers are locked in until the earlier of July 1,2007 or 2003, which impacted the recognition and classification of the termination of capped rates, with a one-time adjustment of the changes infair value, including settlements, of contracts held for fuel factor, effective July 1, 2007 through December 31, 2010, with energy trading and other purposes. no adjustment for previously incurred over-recovery or under-recovery, thus eliminating deferred fuel accounting for the Virginia Crude Oil Buy/Sell Arrangements jurisdiction. As a result, approximately 12% of the cost of fuel Dominion enters into buy/sell and related agreements as a means used inelectric generation and energy purchases used to serve to reposition its offshore Gulf of Mexico crude oil production to utility customers issubject to deferral accounting. Prior to the more liquid marketing locations onshore. Dominion typically enters amendments to the Virginia Electric Utility Restructuring Act into either a single or a series of buy/sell transactions inwhich it (Virginia Restructuring Act) and the Virginia fuel factor statute in sells its crude oil production at the offshore field delivery point and 2004, approximately 93% of the cost of fuel used inelectric gen-buys similar quantities at Cushing, Oklahoma for sale to third eration and energy purchases used to serve utility customers had parties. Dominion is able to enhance profitability by selling to a been subject to deferral accounting. Deferred costs associated wide array of refiners and/or trading companies at Cushing, one of' with the Virginia jurisdictional portion of expenditures incurred the largest crude oil markets inthe world, versus restricting sales through 2003 continue to be reported as regulatory assets, pending to a limited number of refinery purchasers inthe Gulf of Mexico. recovery through future rates.

These transactions require physical delivery of the crude oil and the risks and rewards of ownership are evidenced by titie transfer, Income Taxes assumption of environmental risk, transportation schedulirig and Dominion and its subsidiaries file a consolidated federal income counter party nonperformance risk. tax return. Where permitted by regulatory authorities, the treat-Under the primary guidance of Emerging Issues Task Force ment of temporary differences can differ from the requirements of (EITF) Issue No. 99-19, Reporting Revenue Gross as a Principal Statement of Financial Accounting Standards (SFAS) No. 109, versus Netas an Agent, Dominion presents the sales and pur- Accounting for Income Taxes. Accordingly, a regulatory asset has chases related to its crude oil buy/sell arrangements on a gross been recognized~if it is probable that future revenues will be pro-basis in its Consolidated Statements of Income. The EITF iscur- vided forthe payment of deferred tax liabilities. Dominion estab-rently discussing Issue No. 04-13, Accounting for Purchases and lishes a valuation allowance when it is more likely than not that all Sales of Inventory with the Same Counterparty. which specifically or a portion of a deferred tax asset will not be realized. Deferred focuses on purchase and sale transactions made pursuant to crude investment tax credits are amortized over the service lives of the oil buy/sell arrangements. The EITF isevaluating whether these properties giving rise to the credits.

types of transactions should be presented net in the Consolidated Stock-based Compensation Statements of Income. While resolution of this issue may affect Dominion sponsors a plan that provides stock-based awards to direc-the income statement presentation of these revenues and tors, executives and other key employees. Under the plan, Dominion expenses, there would be no impact on Dominion's results of grants stock options and restricted stock awards that vest over periods operations or cash flows. Amounts currently shown on a gross ranging from one to five years. Options have contractual terms that D 2004 IPage 57

Notes to Consolidated Financial Statements. Continued range from six and a half to ten years. Thirty million shares of common hand, cash inbanks and temporary investments purchased with a stock are registered under the plan, with approximately eight million remaining maturity of three months or less.

shares available for new grants as of December 31,2004.

Inventories Dominion also had three plans under which its directors were Materials and supplies and fossil fuel inventories are valued granted their stock retainers, deferred their cash fees and accumu-primarily using the weighted-average cost method. Stored gas lated stock equivalents. InDecember 2004, these three directors' inventory used inlocal gas distribution operations is valued using the plans were amended to freeze participation and prohibit deferral of last-in-first-out (LIFO) method. Under the LIFO method, those compensation or granting of new benefits after December 31, 2004 inventories were valued at $59 million at both December 31, 2004 to comply with new deferred compensation requirements of Section and 2003. Based on the average price of gas purchased during 2004, 885 of the American Jobs Creation Act of 2004 (the Act) and Section the cost of replacing the current portion of stored gas inventory 409A of the Internal Revenue Code of 1986, as amended (the Code).

exceeded the amount stated on a LIFO basis by approximately $302 A new directors' plan was approved by the Board to permit the million. Stored gas inventory held by certain nonregulated gas oper-deferral of compensation earned by Dominion's non-employee direc-ations is valued using the weighted-average cost method.

tors after December 31, 2004 in accordance with the Act and Section 409A of the Code and provides comparable benefits to those pre- Derivative Instruments viously included under the three frozen directors' plans. The new Dominion uses derivative instruments such as futures, swaps, directors' plan issubject to shareholder approval. forwards and options to manage the commodity, currency Dominion measures compensation expense for stock-based exchange and financial market risks of its business operations.

awards issued to its employees using the intrinsic value method Dominion also manages a portfolio of commodity contracts held for prescribed by Accounting Principles Board Opinion No. 25, trading purposes as part of its strategy to market energy and to Accounting for Stock Issued to Employees, and related inter- manage related risks.

pretations. Under this method, compensation expense for All derivatives, except those for which an exception applies, restricted stock awards equals the fair value of Dominion's are reported on the Consolidated Balance Sheets at fair value. One common stock on the date of grant. Stock option awards generally of the exceptions-normal purchases and normal sales-may be do not result incompensation expense since their exercise price is elected when the contract satisfies certain criteria, including a typically equal to the market price of Dominion's common stock on requirement that physical delivery of the underlying commodity is the date of grant. Compensation expense, if any, for both types of probable. Expenses and revenue resulting from deliveries under awards is recognized on a straight-line basis over the stated normal purchase contracts and normal sales contracts, vesting period of the award. respectively, are included inearnings at the time of contract per-The following table illustrates the pro forma effect on net income formance. Derivative contracts that are subject to fair value and earnings per share (EPS) if Dominion had applied the fair value accounting, including unrealized gain positions and purchased recognition provisions of SFAS No. 123, Accounting for Stock-Based options, are reported as derivative assets. Derivative contracts Compensation, to stock-based employee compensation: representing unrealized losses and options sold are reported as derivative liabilities. For derivatives that are not designated as Year Ended December 31, 2004 2003 2002 hedging instruments, any changes infair value are recorded in (millions) earnings.

Net income-as reported $1.249 S318 $1,362 Add: actual stock-based compensation expense, net of taxi" Valuation Methods 10 10 5 Deduct: pro forma stock-based Fair value is based on actively quoted market prices, if available. In compensation expense, net of tax (20) 038) (521 the absence of actively quoted market prices, Dominion seeks Net income-pro forma $1,239 $ 292 $1,315 indicative price information from external sources, including broker Basic EPS-as reported $ 3.80 $1.00 S 4.85 quotes and industry publications. If pricing information from Basic EPS-pro forma 3.77 0.92 4.68 external sources is not available, Dominion must estimate prices Diluted EPS-as reported 3.78 1.00 4.82 Diluted EPS-pro forma based on available historical and near-term future price 3.75 0.92 4.65 information and certain statistical methods, including regression (1j Actual stock-based compensation expense reflects primarily the issuance of restricted stock. analysis.

For options and contracts with option-like characteristics where Cash and Cash Equivalents pricing information is not available from external sources, Current banking arrangements generally do not require checks to be Dominion generally uses a modified Black-Scholes Model that funded until actually presented for payment At December 31, 2004 considers time value, the volatility of the underlying commodities and 2003, accounts payable includes $158 million and $123 million, and other relevant assumptions when estimating fair value. Other respectively of checks outstanding but not yet presented for pay- option models are used by Dominion under special circumstances, ment. For purposes of the Consolidated Statements of Cash Flows, including a Spread Approximation Model, when contracts include Dominion considers cash and cash equivalents to include cash on different commodities or commodity locations and a Swing Option 0 2004 /Page 58

Notes to Consolidated Financial Statements. Continued 4 '. ' . ' . ,'t,,

.,.y K*

Model, when contracts allow either the buyer or seller the ability generally be offset currently in earnings by the recognition of to exercise within a range of quantities. For contracts with unique changes inthe hedged item's fair value.

characteristics. Dominion estimates fair value using a discounted Statement of Income Presentation-Gains and losses on.

cash flow approach deemed appropriate in the circumstances and: derivatives designated as hedges. when recognized, are included in applied consistently from period to period. If pricing information is operating revenue, operating expenses or interest and related not available from external sources, judgment isrequired to charges inthe Consolidated Statements of,Income. Specific line item develop the estimates of fair value. For individual contracts, the classification isdetermined based on the nature of the risk under-use of different valuation models or assumptions could have a lying individual hedge strategies. The portion of gains or losses on material effect on the contract's estimated fair value. hedging instruments determined to be ineffective and the portion of gains or losses on hedging instruments excluded from the, Derivative Instruments Designated as Hedging Instruments measurement of the hedging relationship's effectiveness, such as,.

Dominion designates a substantial portion of derivative instruments, gains or losses attributable to changes in the time value of options, held for purposes other than trading, as fair value or cash flow or changes in the difference between spot prices and forward prices, hedges for accounting purposes. For all derivatives designated as are included inother operations and maintenance expense. - -

hedges, the relationship between the hedging instrument and the-hedged item is formally documented, as well as the risk manage Derivative lIstrumentsHeld for Trading and Other Purposes ment objective and strategy for using the hedging instrument. As part of its strategy to market energy and to manage related' Dominion assesses whether the hedge relationship between the risks, Dominion manages a portfolio of commodity-based derivative and the hedged item ishighly effective inoffsetting derivative instruments held for trading purposes, primarily natural changes in fair value or cash ffows both at the inception of the gas and electricity. Dominion uses established policies and proce-hedge and on an ongoing basis.'Any change in fair value of the dures to manage the risks associated with the price fluctuations in derivative that is not effective inoffsetting changes inthe fair value these energy cmmodities and uses various derivative instruments or cash flows of the hedged item is recognized currently ineamirigs. to reduce risk by creating offsetting market positions.

Also, management may elect to exclude certain gains or losses on Dominion may also hold certain derivative instruments that are' hedging instruments from the measurement of hedge effectiveness- not held for trading purposes and are not designated as hedges for such as gains or losses attributable to changes in the timd value of' accounting purposes. However. to the extent Dominion does not options or changes inthe difference between spot prices and for-"' hold offsetting positions for such derivatives, management' ward prices, thus requiring that such changes be recorded currently believes these instruments would represent economic hedges that-in earnings. Dominion discontinues hedge accounting prospectively mitigate exposure to fluctuations incommodity prices. interest for derivatives that have ceased to be highly effective hedges.' rates and foreign exchange rates. ' '

Cash FlowHedges-A significant portion of Dominion's hedge Statement'of Income Presentation:

strategies represents cash flow hedges of the variable price risk

• Derivatives Held for Trading Purposes:AII changes in fair value, -

associated with the purchase and sale of electricity, natural gas and' . including amounts realized upon settlement, are presented in oil. Dominion also uses foreign currency forward contracts to hedge' revenue on anet basis as nonregulated electric sales, the variability in foreign exchange rates and interest rate swaps to nonregulated gas sales and other revenue.,

hedge its exposure to variable interest rates on long-temi debt. For

• Financially-Settled Derivaiives-Not Held for Trading Purposes cash flow hedge transactions inwhich Dominion is hedging the or Designated as Hedging Instruments:AII unrealized changes variability of cash flows, changes inthe fair value of the derivative in fair value and settlements are presented in other operations' are reported inaccumulated other comprehensive income (loss)J.-; and maintenance expense on a net basis.

(AOCI), to the extent effective inoffsetting changes in the hedging

• Physically-Settled Derivatives-Not Held for Trading Purposes relationship, until earnings are affected by the hedged item. For cash, or Designated as Hedging Instruments: Effective October 1.

flow hedge transactions that involve a forecasted transaction, - 2003, all statement of income related amounts for physically.

Dominion would discontinue hedge accounting if the occurrence of .. settled derivative sales contracts are presented in revenue, the forecasted transaction was determined to be no longer probable.,. while all statement of income related amounts for physically.

Dominion would reclassify any derivative gains or losses reported in;. settled derivative purchase contracts are reported in expenses.

AOCI to earnings when the forecasted item is included in earnings, if: For'periods prior to October 1,2003, unrealized changes infair it should occur, or earlier, if it becomes probable that the forecasted value for physically settled derivative contracts are presented transaction would not occur.. . inother operations and maintenance expense on a net basis.

Fair Value Hedges-Dominion also engages in fair value Effective January 1,2003, Dominion recognizes revenue or' hedges by using derivative instruments to mitigate the fixed price expense from all non-derivative energy-related contracts on a exposure inherent infirm commodity commitments and certain gross basis at the time of contract performance, settlement or natural gas inventory. Inaddition, Dominion has designated termination. Prior to 2003, all energy trading contracts, including' interest rate swaps as fair value hedges to manage its interest.- non-derivative contracts, were recorded at fair value with changes rate exposure on certain fixed rate long-term debt. For fair value infair value reported inrevenue on anet basis.

hedge transactions, changes in the fair value of the derivative will.

D 2004/Page 59

Notes to Consolidated Financial Statements, Continued Investment Securities Depreciation of property, plant and equipment iscomputed on the Dominion accounts for and classifies investments inmarketable straight-line method based on projected service lives. Dominion's equity and debt securities intwo categories. Debt and equity secu- depreciation rates on property, plant and equipment are as follows:

rities purchased and held with the intent of selling them inthe near 2004 2003 2002 term are classified as trading securities. Trading securities are reported at fair value with net realized and unrealized gains and Ipercent)

Generation 2.10 1.95 2.34 losses included inearnings. All other debt and equity securities are Transmission 2.21 2.22 2.26 classified as available-for-sale securities. These are reported at fair Distribution 3.19 3.18 3.27 value with realized gains and losses and any other-than-temporary Storage 3.05 2.81 2.47 Gas gathering and processing 2.58 2.39 2.31 declines infair value included inearnings and unrealized gains and General and other 5.49 5.67 5.74 losses reported as a component of AOCI, net of tax.. . -

Dominion analyzes all securities classified as available-for-sale Amortization of nuclear fuel used inelectric generation is to determine whether a decline infair value should be considered provided on a units-of-production basis sufficient to fully amortize, other-than-temporary. Retained interests from securitizations of over the estimated service life, the cost of the fuel plus permanent financial assets are evaluated inaccordance with EITF Issue No. storage and disposal costs.

99-20, Recognition of Interest Income and Impairments of Pur-In2002, Dominion extended the estimated useful lives of most of chased and Retained Beneficial Interests in Securitized Financial its fossil fuel power stations and electric transmission and dis-Assets. For other securities, Dominion uses several criteria to tribution property based on depreciation studies that indicated evaluate other-than-temporary declines, including length of time longer lives were appropriate. The change reduced annual deprecia-over which the market value has been lower than its cost, the tion expense for'those assets by approximately $68 million.

percentage of the decline as compared to its average cost and the Dominion follows the full cost method of accounting for gas expected fair value of the security. If the market value of the secu-and oil exploration and production activities prescribed by the SEC.

rity has been less than cost for greater than nine months and the Under the full cost method, all direct costs of property acquisition, decline in value is greater than 5 0%of its average cost, the secu-exploration and development activities are capitalized. These rity is written down to its expected recovery value. If only one of capitalized costs are subject to a quarterly ceiling test. Under the the above criteria is met, a further analysis is performed to eval-ceiling test, amounts capitalized are limited to the present value of uate the expected recovery value based on third party price tar-estimated future net revenues to be derived from the anticipated gets. If the third party price quotes are below the security's production of proved gas and oil reserves, assuming period-end average cost and one of the other criteria has been met, the pricing adjusted for cash flow hedges in place. If net capitalized decline isconsidered other-than-temporary and the security is costs exceed the ceiling test at the end of any quarterly period, written down to its expected recovery value.

then a permanent write-down of the assets must be recognized in Property, Plant and Equipment that period. The ceiling test isperformed separately for each cost Property, plant and equipment, including additions and replacements, center, with cost centers established cn a country-by-country isrecorded at original cost, including labor, materials, asset retirement basis. Approximately 16% of Dominion's anticipated production is costs, other direct costs and capitalized interest. The cost of repairs hedged by qualifying cash flow hedges, for which hedge-adjusted and maintenance, including minor additions and replacements, is prices were used to calculate estimated future net revenue.

charged to expense as incurred. In2004, 2003 and 2002, Dominion Whether period-end market prices or hedge-adjusted prices were capitalized interest costs of $70 million, $96 million and $95 million, used for the portion of production that is hedged, there was -o respectively. ceiling test impairment as of December 31, 2004. Dominion For electric distribution and transmission property and natural adopted Staff Accounting Bulletin No. 106 (SAB 106) as of gas property subject to cost-of-service utility rate regulation, the December 31, 2004 and, accordingly, excludes future cash flows depreciable cost of such property, less salvage value, is charged to associated with settling AROs that have been accrued on the accumulated depreciation at retirement. Cost of removal collec- balance sheet pursuant to SFAS No. 143, Accounting forAsset tions from utility customers and expenditures not representing Retirement Obligations, from its calculations under the full cost asset retirement obligations (AROs) are recorded as regulatory ceiling test.

liabilities or regulatory assets. Depreciation of gas and oil producing properties iscomputed For generation-related property, cost of removal not associated using the units-of-production method. Under the full cost method, with AROs ischarged to expense as incurred. Dominion records the depreciable base of costs subject to amortization also includes gains and losses upon retirement of generation-related property estimated future costs to be incurred indeveloping proved gas and based upon the difference between proceeds received, if any, and oil reserves, as well as capitalized asset retirement costs, net of the property's undepreciated basis at the retirement date. projected salvage values. The costs of investments inunproved properties are initially excluded from the depreciable base. Until the properties are evaluated, a ratable portion of the capitalized costs is periodically reclassified to the depreciable base, D 2004/ Page 60

Notes to Consolidated Financial Statements, Continued determined on a property by property basis, over terms of under- trust investments were reported at fair value with the accumulated lying leases. Once a property has been evaluated, any remaining provision for decommissioning reported as a liability. Net realized and capitalized costs are then transferred to the depreciable base. In unrealized earnings on the trust investments, as well as an offsetting addition, gains or losses on the sale or other disposition of gas and expense to increase the accumulated provision for decommissioning.

oil properties are not recognized, unless the gain or loss would was recorded as a component of other income (loss).

significantly alter the relationship between capitalized costs and Merchant Nuclear Plant-Dominion recognized, as a liability on proved reserves of natural gas and oil attributable to a country. the Consolidated Balance Sheet, an obligation to decommission its See Asset Retirement Obligations for a discussion of gas and oil merchant nuclear plant. The obligation was based upon its esti-abandonment and dismantlement costs. mated fair value, using discounted cash flows of expected costs to perform the decommissioning activities. Accretion of the obligation Goodwill and Intangible Assets was reported as depreciation expense. The external trusts were Dominion evaluates goodwill for impairment annually, as of April accounted for as available-for-sale investments with realized gains 1st, and whenever an event occurs or circumstances change in the and losses recogrized in other income (loss) and unrealized gains interim that would more likely than not reduce the fair value of a and losses reported inAOCI.

reporting unit below its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives. Gas and Oil Dismantlement andAbandonment Costs-2002 Prior to 2003, Dominion's accounting and reporting practices for Impairment of Long-Lived and Intangible Assets future dismantlement and restoration activities for its gas and oil Dominion performs an evaluation for impairment whenever events wells and platforms recognized such costs as a component of or changes in circumstances indicate that the carrying amount of depletion expense and included them inaccumulated depreciation, long-lived assets or intangible assets with finite lives may not be depletion and amortization.

recoverable. These assets are written down to fair value if the sum of the expected future undiscounted cash flows is less than the Amortization of Debt Issuance Costs carrying amounts. Dominicn defers and amortizes debt issuance costs and debt pre-miurns or discounts over the expected lives of the respective debt Regulatory Assets and Liabilities issues, considering maturity dates and, if applicable, redemption For utility operations subject to federal or state cost-of-service rate rights held by others. As permitted by regulatory authorities, gains or regulation, regulatory practices that assign costs to accounting periods losses resulting from the refinancing of debt allocable to utility may differ from accounting methods generally applied by nonregulated operations subject to cost-based rate regulation have also been companies. When it isprobable that regulators will al!ow for the deferred and amortized over the lives of the new issues.

recovery of current costs through future rates charged to customers, Dominion defers these costs and recognizes regulatory assets inits financial statements that otherwise would be expensed by non-regulated companies. Likewise, Dominion recognizes regulatory 3.Newly Adopted Accounting Standards liabilities inits financial statements when it is probable that regulators 2004 will allow for customer credits through future rates and when revenue FSP FAS 142-2 iscollected from custorrers for expenditures that are not yet incurre. Dominion adopted Financial Accounting Standards Board (FASB)

Staff Position 142-2, Application of FASB Statement No. 142.

Asset Retirement Obligations Goodwill and Other Intangible Assets, to Oil- and Gas- Producing Beginning in2J03, Dominion recognizes its AROs at fair value as Entities, (FSP 142-2) in September 2004. FSP 142-2 was issued to incurred, capitalizing these amounts as costs of the related clarify that an exception outlined inSFAS No. 142 includes the tangible long-lived assets. Due to the absence of relevant market balance sheet classification of drilling and mineral rights of oil and information, fair value is estimated using discounted cash flow gas producing entities. In accordance with the guidance in FSP analyses. Dominion reports the accretion of the liabilities due to 142-2, Dominion continues to present its oil and gas drilling rights the passage of time as an operating expense. In addition, begin-as tangible assets classified in property, plant and equipment.

ning in2003, Dominion classifies all investments held by its decommissioning trusts as available-for-sale, and recognizes real- FIN 46R ized gains and losses in other income (loss) and records unrealized Dominion adopted FASB Interpretation No. 46 (revised December gains and losses inAOCI. 2003), Consolidation of Variable Interest Entities, (FIN 46R) for its interests inVIEs that are not considered special purpose entities on Nuclear Decommissioning-2002 March 31, 2004. As discussed below, Dominion adopted FIN 46R for UtilityNuclearPlants--n accordance with the accounting policy its interests inspecial purpose entities on December 31,2003. FIN 46R recognized by regulatory authorities having jurisdiction over its electric addresses the identification and consolidation of VIEs, which are enti-utility operations, Dominion recognized an expense for the future cost ties that are not controllable through voting interests or inwhich the of decommissioning inamounts equal to the sum of amounts collected VIEs' equity investors do not bear the residual economic risks and from ratepayers and earnings on trust investments dedicated to rewards inproportion to voting rights. There was no impact on Domin-funding the decommissioning of Dominion's utility nuclear plants. The D 2004/ Page 61

1.

Notes to Consolidated Financial Statements, Continued ion's results of operations or financial position related to this adoption. ion's FIN 46R request. Dominion had purchased $20 million, $20 Dominion is a party to long-term contracts for purchases of million and $21 million of electric generation capacity and $4mil-electric generation capacity and energy from qualifying facilities lion, $7million and $3million of electric energy under this power and independent power producers. Certain variable pricing terms purchase agreement in2004, 2003 and 2002, respectively. In addi-insome of these contracts cause them to be considered potential tion, in February 2005, Dominion paid $42 million incash and variable interests that require evaluation under the provisions of assumed $62 million of debt to terminate its power purchase FIN 46R. If a power generator that holds one of these specific agreement and to acquire the related generating facility from the types of contracts is determined to be a VIE and Dominion is supplier entity that Dominion had determined to be a VIE and, in determined to be the primary beneficiary, Dominion would be which, its power purchase agreement represented a significant required to consolidate the entity in its financial statements. variable interest. Dominion purchased $23 million, $23 million and Consolidation of one of these potential VIEs would primarily result $24 million of electric generation capacity and $8million, $10 in the addition of property, plant and equipment. long-term debt million and $5million of electric energy under this power purchase and minority interest to Dominion's Consclidated Balance Sheets. agreement in2004, 2003 and 2002, respectively.

The impact on Dominion's Consolidated Statements of Income For those six potential VIE supplier entities that have not pro-would be that purchased energy and capacity expenses attribut- vided sufficient information, Dominion will continue its efforts to able to the long-term contract with the VIE would be replaced by obtain information and will complete an evaluation of its relation-the VIE's operations, maintenance and interest expenses. The VIE's ship with each of these potential VIEs, if sufficient information is results of operations would be reported as income attributable to a ultimately obtained. Dominion has remaining purchase commitments minority interest, and would not affect Dominion's net income. The with these six potential VIE supplier entities of $2.6 billion at debt of these potential VIEs, even if included in Dominion's Con- December 31, 2004. These commitments are incorporated inDomin-solidated Balance Sheets, would be nonrecourse to Dominion. ion's disclosure of unconditional purchase obligations included in At March 31, 2004, Dominion had determined that its power Note 22. Dominion paid $249 million, $250 million and $300 million purchase agreements with ten of these entities would require for electric generation capacity and $185 million, $168 million and further analysis under FIN 46R. Each of these facilities began $120 million for electric energy to these entities in2004, 2003 and commercial operations and service to Dominion under the long- 2002, respectively. Dominion's exposure to losses from its involve-term contracts prior to December 31, 2003. Since these entities ment with these entities cannot be determined since losses, if any, were established and are legally owned by parties not affiliated would be represented by either: 1)the difference between (a)the with Dominion, Dominion submitted requests for information amount payable by Dominion for energy and capacity under the long-needed to evaluate the entity and its contractual relationship with term contract and (b)amounts recoverable through sales to retail the entity under FIN 46R. In addition, Dominion informed the enti- electric customers inits service territory or wholesale market trans-ties that, if the results of its evaluation were to indicate that actions; or 2)if the potential VIE supplier fails to perform, any Dominion should consolidate the entity, it would also require amount paid by Dominion to obtain replacement energy and capacity periodic financial information inorder to perform the accounting inexcess of the amounts otherwise payable under the long-term required to consolidate the entity inits financial statements. The contract with the potential VIE supplier entity.

objectives of the FIN 46R evaluation are to determine: (11) whether The EITF has added a project to its agenda to consider what Dominion's interest, represented by the power purchase contract, variability should be considered when determining whether an isa significant variable interest; (2)whether the supplier entity is a interest is a,variable interest. It is uncertain how this EITF project VIE; and (3)if the supplier entity is a VIE, whether Dominion isthe or other future efforts to further interpret FIN 46R could impact primary beneficiary. Dominion's conclusions based on its use of information received.

In response to these requests, five of the potential VIE supplier EITF04-8 entities provided some, but limited, information. After completing On December 31, 2004, Dominion adopted EITF Issue No. 04-8, The its analysis of this information, Dominion concluded that one of the' Effect of Contingently Convertible Instruments on Diiuted Earnings supplier entities is a VIE, its power purchase contract represented per Share, which requires the shares issuable under contingently a significant variable interest inthe VIE, but Dominion is not its convertible instruments to be included in the diluted EPS calculation primary beneficiary. Inaddition, using the limited information regardless of whether the market price trigger (or other contingent received, Dominion concluded that it does not hold sigrificant feature) has been met. Prior to adoption, Dominion exchanged $219 variable interests intwo of the potential VIE supplier entities.

million of outstanding contingent convertible senior notes for new Since the enactment of the Virginia Restructuring Act, notes with a conversion feature that requires that the principal Dominion has sought to renegotiate or terminate long-term power amount of each note be repaid incash. The new notes outstanding purchase contracts inits efforts to reduce the cost structure of its on December 31, 2004 were included in the diluted EPS calculation generation-related operations. In November 2004, Dominion paid retroactive to the date of issuance using the method described in

$92 million to terminate its power purchase agreement and to EITF 04-8. Under this method, the number of shares included inthe acquire the related generating facility from one of the potential VIE denominator of the diluted EPS calculation iscalculated as the net suppliers that had not provided information inresponse to Domin-shares issuable for the reporting period based upon the average D 20041 Page 62

Notes to Consolidated Financial Statements, Continued market price for the period. This did not result inan increase to the fication of income statement related amounts for derivative con-average shares outstanding used inthe calculation of Dominion's tracts. Income statement amounts related to periods prior to October diluted EPS since the conversion price included inthe notes was 1,2003 are presented as originally reported. See Note 2.

greater than the average market price.

Statement 133 Implementation Issue No. C20 SAB 106 Inconnection with a request to reconsider an interpretation of SFAS In September 2004, the SEC issued SAB 106, which provides No.133, Accounting for Derivative Instruments and Hedging 1 guidance to oil and gas' companies following the full cost Activities, FASB issued Statement 133 Implementation Issue No.

accounting method regarding the application of SFAS No. 143. C20, Interpretation of the Meaning of 'Not ClearlyandCloselyfRela-SAB 106 requires companies calculating the full cost ceiling test to ted' inParagraph 10/b) regarding Contracts with a Price Adjustment exclude future cash outflows associated with settling AROs that Feature. Issue C20 establishes criteria for determining whether a have been accrued on the balance sheet as required by SFAS No. contract's pricing terms that contain broad market indices (e.g., the 143. However, estimated dismantlement and abandonment costs consumer price index) could qualify as a normal purchase or sale related to future development activities, which are not required to and, therefore, not be subject to fair value accounting. Dominion has be accrued under SFAS No. 143, should continue to be included in several contracts that qualify as normal purchase and sales con-the full cost ceiling test. Dominion adopted the provisions of SAB tracts under the Issue C20 guidance. However, the adoption of Issue 106 during the fourth quarter of 2004. There was no financial C20 required the contracts to be initially recorded at fair value as of statement impact associated with the adoption of SAB 1G6. October 1 2003, resulting inthe recognition of an after-tax charge of

$75 million, representing the cumulative effect of the change in 2003 accounting principle. As normal purchase and sales contracts, no SFASNo. 143 further changes infair value will be recognized.

Effective January 1,2003, Dominion adopted SFAS No. 143, which provides accounting requirements for the recognition and measure- FIN 46R ment of liabilities associated with the retirement of tangible long- On December 31, 2003, Dominion adopted FIN 46R for its interests lived assets. The effect of adopting SFAS No. 143 for 2003, as in special purpose entities, resulting in the consolidation of several compared to an estimate of net income reflecting the continuation of special purpose lessor entities through which Dominion had con-former accounting policies, was to increase net income by $201 structed, financed and leased several new power generation million. The increase iscomprised of a $180 million after-tax gain, projects, as well as its corporate headquarters and aircraft. As a representing the cumulative effect of a change inaccounting; result, the Consolidated Balance Sheet as of December 31, 2003 principle and an increase in income before the, cumulative effect of a reflects an additional $644 million innet property, plant and change in accounting principle of $21 million. equipment and deferred charges and $688 million of related debt.

This resulted inadditional depreciation expense of approximately EITF02-3

$20 million in2004. The cumulative effect in 2003 of adopting On January 1,2003, Dominion adopted EITF Issue No. 02-3, Issues FIN 46R for Dominion's interests in special purpose entities was an Involved in Accounting for Derivative Contracs Held for Trading after-tax charge of $27 million, representing depreciation expense Purposes and Contracts Involved inEnergy Trading and Risk and amortization associated with the consolidated assets.

ManagementActivities, that rescinded ElTFlssue No.98-10, From 1997 through 2002, Dominion established five capital Accounting for Contracts Involved inEnergy Trading .nd Risk trusts that sold trust preferred securities to third party investors.

ManagementActivities. Adopting EITF 02-3 resulted intfhe dis'-

Dominion received the proceeds from the sale of the trust pre-continuance of fair value accounting for non-derivativ'e contracts ferred securities in exchange for various junior subordinated notes held for trading purposes. Those contracts are recognized as rever'ue issued by Dominion to be held by the trusts. Upon adoption of FIN or expense at the time of contract performance, settlement or 46R, Dominion began reporting as long-term debt its junior sub-termination. The EITF 98-10 rescission was effective for non-ordinated notes held by the trusts rather than the trust preferred derivative energy trading contracts initiated after October 25, 2002.

securities. As a result in2004, Dominion reported interest expense For all non-derivative energy trading contracts initiated prior to on the junior subordinated notes rather than preferred distribution October 25, 2002, Dominion recognized a loss of $67 million (after expense on the trust preferred securities.

taxes of $43 million) as the cumulative effect of this change in accounting principle on January 1.2003. Pro Forma Information Reflecting Adoption of New Standards EITF03-11 Disclosure requirements associated with the adoption of FIN 46R Dominion adopted EITF Issue No. 03-11, Reporting Realized Gains and SFAS No. 143 require a presentation of pro forma net income andLosses on Derivative Instruments ThatAre Subject to FASB and EPS for 2002 as if Dominion had applied the provisions of Statement No. 133 and Not Held for Trading Purposes'as Defined those standards as of January 1,2002. Other standards adopted inIssue No. 02-3, on October 1.2003. EITF 03-11 addresses classi-D 2004 / Page 63

Notes to Consolidated Financial Statements. Continued during 2004 and 2003 do not require pro forma information and are SFAS No. 151 excluded from the amounts presented below. InNovember 2004, the FASB issued SFAS No.151, Inventory Costs-an amendment ofARB No. 43, Chapter 4,which clarifies that Basic Diluted Amount EPS EPS abnormal amounts of idle facility expense, handling costs, freight, and (inmillions, except per share wasted materials (spoilage) should be recognized as current period amounts) charges, and requires that inmanufacturing operations, allocation of 2002 fixed production overheads to the costs of conversion be based on the Reported net income $1.362 $4.85 $4.82 normal capacity of the production facility. Dominion will adopt the Adjusted net income 1.363 4.85 4.82 provisions of this standard prospectively beginning January 1,2006 and does not expect the adoption to have a material impact on its results of operations and financial condition.

4. Recently Issued Accounting Standards EITF 03-1 SFAS No. 153 In accordance with FSP EITF 03-1-1, Dominion delayed its adoption In December 2004, the FASB issued SFAS No. 153, Exchanges of of the recognition and measurement provisions of EITF Issue No. Nonmonetary Assets-an amendment ofAPB Opinion No. 29, 03-1, The Meaning of Other-Than-Temporary lmbairmentand Its which requires that all commercially substantive exchange trans-Application to Certain Investments, which provides guidance for actions, for which the fair value of the assets exchanged are reli-evaluating and recognizing other-than-temporary impairments for ably determinable, be recorded at fair value, whether or not they certain investments indebt and equity securities. This delay will are exchanges of similar productive assets. This amends the be in effect until the FASB teaches a final conclusion on issues exception from fair value measurements inAPB No. 29, Accounting raised in its proposed FSP 03-1-a, which relates primarily to for Nonmonetary Transactions, for nonmonetary exchanges of implementation issues concerning certain types of debt securities. similar productive assets and replaces it with an exception for only Pending the adoption of any new guidance that may be final- those exchanges that do not have commercial substance.

ized inthe future. Dominion has continued to evaluate its Dominion will adopt the provisions of this standard prospectively available-for-sale securities for other-than-temporary impairment beginning July 1,2005 and does not expect the adoption to have a based upon the accounting policy described in Note 2.In addition material impact on its results of operations and financial condition.

to issues being addressed by the FASB in FSP 03-1 -a.Dominion and other entities inthe electric industry have sought additional guidance from the FASB concerning the proper application of EITF 5.Acquisitions 03-1 to debt and equity securities held innuclear decommissioning USGen Power Plants trusts. Given the delayed effective date and the request for addi- InJanuary 2005, Dominion completed the acquisition of three tional guidance described above, Dominion cannot predict what. electric power generation facilities from USGen New England, Inc.

the initial or ongoing impact of applying EITF 03-1 to its nuclear (USGen) for $642 million incash. The acquisition was part of a decommissioning trust investments may have on its results of bankruptcy court-approved divestiture of generation assets by operations and financial condition at this time. USGen. The plants include the 1,521-megawatt Brayton Point SFAS No. 123R Station in Somerset, Massachusetts; the 743-megawatt Salem InDecember 2004, the FASB issued SFAS No. 123 (revised 2004), Harbor Station inSalem, Massachusetts; and the 426-megawatt Share-Based PaymentiSFAS No. 123R), which requires that the Manchester Street Station in Providence, Rhode Island. These compensation cost relating to share-based payment transactions be assets will be included in the Dominion Generation operating recognized inthe financial statements. The cost will be measured segment. Dominion did not acquire any of the facilities' debt inthe based on the fair value of the equity or liability instruments issued. transaction and plans to finance the acquisition with a combina-SFAS No. 123R covers awide range of share-based compensation tion of debt and equity.

arrangements, including share options, restricted share plans, Cove Point LNG Limited Partnership performance-based awards, share appreciation rights and employee In September 2002, Dominion acquired 100% ownership of Cove share purchase plans. The requirements of SFAS No. 123R are effec- Point LNG Limited Partnership (Cove Point), a cost-based rate-tive for unvested awards outstanding as of July 1,2005 as well as for regulated entity, from a subsidiary of The Williams Companies for awards granted, modified, repurchased or cancelled on or after that $225 million incash. Dominion recorded $75 million of goodwill date. Compensation expense expected to be recognized for unvested representing the excess of the purchase price over the regulatory stock options outstanding at adoption is not expected to be material basis of Cove Point's assets acquired and liabilities assumed. Cove and Dominion's accounting for restricted stock awards is not expected Point's assets include an LNG natural gas import and storage to change significantly under the new standard. Dominion is currently facility located near Baltimore, Maryland and an approximately 85-evaluating the financial statement impact of applying SFAS No. 123R mile natural gas pipeline. Cove Point became fully operational in to future grants of stock-based awards. August 2003. Cove Point is included in the Dominion Energy D 2004/ Page 64

Notes to Consolidated Financial Statements, Continued operating segment and the goodwill arising from the acquisition The statutory U.S. federal income tax rate reconciles to the was allocated to that segment for goodwill impairment-testing effective income tax rates as follows:

purposes. Year Ended December 31, 2004 2003 2002 Mirant State Line Ventures, Inc. U.S. statutory rate 35.0%/ 35.0% 35.0%

InJune 2002, Dominion acquired 100% ownership of Mirant State Increases (reductions) resulting from:

Valuation allowance 10.3) 4.0 Line Ventures, Inc. (State Line) from a subsidiary of Mirant Corpo- State taxes, net of federal benefit 2.2 2.2 2.5 ration for $185 million incash. State Line's assets include a 515- Utility plant differences 0.1 10.41 10.1) megawatt generation facility located near Hammond, Indiana. Its Preferred dividends 0.3 0.4 0.3 Amortization of investment tax credits (0.7) -* 10.9) 10.7) operations are included inthe Dominion Generation operating Nonconventional fuel credit 11.8) segment. Other benefits and taxes / foreign operations - 10.5) 0.2 Employee pension and other benefits (0.5) . 10.7) 10.6)

Employee stock ownership plan deduction (0.5) 10.7) 1(0.8)

Other. net - 0.2 (0.7)

6. Operating Revenue Effective tax rate 35.6% . 38.6% 33.3%

Dominion's operating revenue consists of the following:

Year Ended December 31, 2004 2003 2002 Dominion's 2004 and 2003 effective tax rates were negatively impacted by the expiration of nonconventional fuel tax credits. Dominion's 2003 Imillions)

Regulated electric sales $ 5,180 S 4,876 $54,856 effective tax rate was also negatively impacted by an increase inthe Regulated gas sales 1,422 1,258 876 valuation allowance related to federal loss carryforwards at CNG Nonregulated electric sales 1,249 1,130 1,017 International (CNGI). Dominion Telecom, Inc. and DCI that are not Nonregulatedgassales 2,082 1.710 778 Gas transportation and storage 802 740 705 expected to be utilized.

Gas and oil production 1,636 1,503 1,334 Deferred income taxes reflect the net tax effects of temporary differ-Other 1,601 853 652 ences between the carrying amount of assets and liabilities for financial Total operating revenue $13,972 $12,078 $10,218 reporting purposes and the amounts used for income tax purposes.

Dominion's net deferred income taxes consist of the following:

7. Income Taxes At December 31, 2004 2003 (millions)

Income from continuing operations before provision for income Deferred income tax assets:

taxes (pre-tax income), classified by source of income, and the Other comprehensive income $ 594 $ 397 details of income tax expense were as follows: Deferred investment tax credits 31 31 Loss and credit carryforwards 798 424 Year Ended December 31, 2004 2003 2002 Vatuatioa allowance . (328) (3381 (millionsl Total deferred income tax assets 1,095 514 Income before provision for taxes: Deferred income tax liabilities:

U.S. $1,938 51,506 $2,018 Depreciation method and plant basis differences 2,735 2,310 Non-U.S. 26 40 25 Income taxes recoverable through future rates s0 16 Total 1,964 1,546 2.043 Partnership basis differences 567 465 Postretirement and pension benefits 537 571 Income tax expense: Intangible drilling costs 965 833 Current Geological, geophysical and other exploration Federal 62 121 (46) differences 249 220 State . 82 22 13 Deferred state income taxes 494 432 Non-U.S. (3) 1 Other 318 21 Total current 141 144 (33) Total deferred income tax liabilities 5,925 4,888 Deferred Total net deferred income tax liabilities $4,830 $4,374 Federal 580 433 654 State (16) 32 65 Non-U.S. 12 6 13 At December 31, 2004, Dominion had the following loss and Total deferred 576 471 732 credit carryforwards:

Amortization of deferred investment tax

• Federal loss carryforwards of $1.4 billion that expire if credits-net (17) (18) 1181 unutilized during the period 2005 through 2024. A valuation Total income tax expense $ 700 $ 597 $ 681 allowance on $806 million incarryforwards has been established due to the uncertainty of realizing these future deductions;

• State net operating loss carryforwards of $2.4 billion that expire if unutilized during the period 2005 through 2024. A valuation allowance on $988 million has been established for these carryforwards; and D 2004/ Page 65

Notes to Consolidated Financial Statements, Continued

• Federal and state minimum tax credits of $131 million that do o. 2004 2003 2002 not expire and other federal and state income tax credits of $66 (millions) million that will expire if unutilized during the period 2006 Portion of gains (losses) on hedging instruments determined to be ineffective and through 2024. included innet income:

Fair value hedges $ (2) $313 S2 Other Cash flowhedges 10 7 (311 Dominion has not provided for U.S. deferred income taxes or for- Net ineffectiveness S 8 S4 $(291 eign withholding taxes on its remaining undistributed earnings of Portion of gains flosses) on hedging

$135 million from its non-U.S. subsidiaries since those earnings instruments excluded from measurement of are intended to be reinvested indefinitely. effectiveness and included innet income:

As a matter of course, Dominion is regularly audited by federal Fairvalue hedges"0 S 3 S1 . (11 Cash flow hedges l 101 7 (1) and state tax authorities. Dominion establishes liabilities for Total S104 $8 $ (21 probable tax-related contingencies and reviews them inlight of changing facts and circumstances. Although the results of these (1)Amounts relate to changes inthe difference between spot prices and forward audits are uncertain. Dominion believes that the ultimate outcome prices for 2004 and to changes inoptions' time value for 2003 and 2002.

will not have a material adverse effect on Dominion's financial 12)Amounts relate to changes inoptions' time value.

position. Dominion had no significant tax-related contingent The following table presents selected information related to liabilities at December 31, 2004.

cash flow hedges included inAOCI inthe Consolidated Balance American Jobs Creation Act of 2004 Sheet at December 31, 2004:

The Act was signed into law October 22, 2004, and has several Portion Expected provisions for energy companies including a deduction related to Accumulated to be Reclassified taxable income derived from qualified production activities. Under Other to Earnings the Act, qualified production activities include Dominion's electric Comprehensive during the Next generation and oil and gas extraction activities. The Act limits the Income (loss) 12 Months Maximum After Tax After Tax Term deduction to the lesser of taxable income derived from qualified (millions) production activities or the consolidated federal taxable income of Commodities:

Dominion and its subsidiaries. At this time, Dominion does not Gas , $ (673) $1354) 38 months believe the qualified production activities deduction will have a Oil (3081 (1351 36 months material impact on Dominion's results of operations or financial Electricity (2091 11331 36 months InterestfRate (31) 131 258months position in2005. Foreign The Act also allows United States companies to repatriate Currency 40 11 35 months foreign earnings at a substantially reduced tax rate until December Total , 511,1}8 $16141 2005. At the current time, Dominion does not have plans to repa-triate funds to the United States but is continuing its evaluation The actual amounts that will be reclassified to'earnings in2005 and will finalize its plans during 2005. Dominion estimates the will vary from the expected amounts presented above as a result range of foreign earnings that may be repatriated to be $135 mil- of changes in market prices, interest rates and foreign exchange lion to $225 million, which would result in income tax expense in rates. The effect of amounts being reclassified from accumulated the range of $20 million to $35 million. other comprehensive loss to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices con-

8. Hedge Accounting Activities templated by the underlying risk management strategies.

Dominion is exposed to the impact of market fluctuations inthe As a result of damage to certain offshore production facilities price of natural gas, electricity and other energy-related commod- inthe Gulf of Mexico caused by Hurricane Ivan, and the related ities marketed and purchased as well as the currency exchange loss of forecasted oil production for the period from rmid-and interest rate risks of its business operations. Dominion uses September 2004 to May 2005, Dominion discontinued certain cash derivative instruments to mitigate its exposure to these risks and flow hedges effective September 14, 2004. Inconnection with the designates derivative instruments as fair value or cash flow discontinuance of these cash flcw hedges, Dominion reclassified hedges for accounting purposes. Selected information about $71 million of pre-tax losses from AOCI to earnings in 2004. These Dominion's hedge accounting activities follows: amounts were reported inother operations and maintenance expense in the Consolidated Statements of Income.

D 2004/ Page 66

Notes to Consolidated Financial Statements, Continued

9. Discontinued Operations-Telecommunications fair values based on preliminary bids received inconnection with the sale of Dominion Telecom.

Operations Since realization of tax benefits related to the impairment Dominion Fiber Ventures, LLC (DFV) was a joint venture originally charges will be dependent upon Dominion's future tax profile and formed by Dominion and a third-party investor trust (Investor Trust) taxable earnings, management established a valuation allowance to fund the development of its principal subsidiary, Dominion that completely offsets the deferred tax benefits. In addition, Telecom, Inc. (Dominion Telecom). Dominion Telecom was a Dominion increased the valuation allowance on deferred tax facilities-based interchange and emerging local carrier, providing assets previously recognized, resulting ina $48 million increase in broadband solutions to wholesale customers throughout the deferred income tax expense.

eastern United States. Inconnection with its formation, DFV issued

$665 million of 7.05% senior secured notes due March 2005 which 2003-Additional Investments in DFV were secured in part by Dominion convertible preferred stock held The DOV senior notes contained certain stock price and credit in trust. Dominion was the beneficial owner of the trust and thus downgrade triggers that could have resulted inthe issuance of the did not present the.convertible preferred stock inits Consolidated convertible preferred stock held intrust. Inthe first quarter of Balance Sheets. During 2004, as a result of the retirement of DFV's 2003, Dominion purchased $633 million of DFV senior notes to senior notes, the trust was dissolved and the convertible preferred reduce the likelihood that the remarketing of the Dominion con-stock was retired. vertible preferred stock held intrust would ever occur and, in At inception, Dominion's strategy for Dominion Telecom was to connection with the purchase, obtained consent to remove the focus primarily on delivering lit capacity, dark fiber and collocation triggers from the indenture. Dominion paid a total of $664 million services to under-served markets. With the markets for these for the notes acquired and recognized a pre-tax charge of $57 services not growing at rates originally contemplated and the million, reported inother expenses on the Consolidated Statement continuing downward pressure on prices, resulting from excess of Income. The charge consisted of the premium paid to acquire capacity inthe telecommunications industry, Dominion reconsid- the notes, the consent fee paid to the note holders and the recog-ered its investment strategy during 2003. Reflecting a revision in nition of previously unamortized debt costs. After the transaction, long-term expectations for potential growth intelecommunications Dominion owned a total of $644 million of DFV senior notes with service revenue, Dominion approved a strategy to sell its interest the remaining $21 million of outstanding notes held by third par-in the telecommunications business and began reporting Dominion ties.

Telecom as a discontinued operation inthe fourth quarter of 2003. Dominion began consolidating the results of DFV inits Con-solidated Financial Statements inFebruary 2003, as a result of 2004-Sale of Dominion Telecom acquiring substantially all of DFV's outstanding senior notes. Prior In May 2004, Dominion completed the sale of its discontinued to this acquisition, Dominion accounted for DFV as an equity-telecommunication operations to Elantic Telecom, Inc., realizing a method investment, due to the Investor Trust's equity investment loss of $11 million ($7 million after-tax, $0.02 per share) related to and veto rights.

the sale. The results of telecommunications operations, including Inthe fourth quarter of 2003, Dominion purchased the Investor revenue of $8million and a loss before income taxes of $19 mil- Trust's interest in DFV for $62 million, including $2million for lion, are presented as discontinued operations, on a net basis, on accrued dividends. This transaction was accounted for as a pur-the Consolidated Statement of Income for 2004. chase of a minority interest and $60 million was recognized as During July 2004, Elantic Telecom Inc. filed a voluntary petition goodwill and impaired. The purchase enabled Dominion to proceed for reorganization under Chapter 11 of the U.S. Bankruptcy Code in with its strategy to sell Dominion Telecom and, accordingly, the U.S. Bankruptcy Court for the Eastern District of Virginia, classify the business as discontinued operations as of December Richmond Division. Dominion iscurrently assessing its potential 31, 2003. As a result, telecommunications assets (network assets exposure, if any, as a result of this filing. At December 31, 2004, and inventories) and liabilities, both totaling $13 million were Dominion has $9million of remaining guarantees related to classified as held-for-sale, and were included inother current Dominion Telecom. assets and liabilities on the Consolidated Balance Sheet as of 2003-Asset Impairments December 31, 2003. The results of telecommunications operations, The change instrategy in2003 included a review of Dominion including revenue of $18 million and a loss before income taxes of Telecom's network assets and related inventories for impairment. $627 million, were presented as discontinued operations, on a net As a result, Dominion recognized a $566 million impairment of basis, on the Consolidated Statement of Income for 2003.

network assets and related inventories, reflecting the excess of 2003-Other the assets carrying amount over their estimated fair values. This Also early in2003, Dominion recognized a $27 million charge for amount included the allocation of $16 million to the Investor Trust, the reallocation of DFV's equity losses between the Investor Trust representing its minority interest share of these charges. and Dominion. Based on updated projections of DFV's expected net Management determined the estimated fair values with the assis- losses, Dominion and the Investor Trust revised the allocation of tance of an independent appraiser and subsequently updated the equity losses, using cash allocations and liquidation provisions of D 2004/ Page 67

Notes to Consolidated Financial Statements, Continued the underlying limited liability company agreement rather than Potentially dilutive securities with the right to purchase approx-voting interests. imately 5 million, 10 million and 11 million common shares for the years ended 2004, 2003 and 2002, respectively, were not included 2002 Transactions inthe respective period's calculation of diluted EPS because the During 2002, Dominion's Consolidated Financial Statements exercise and purchase prices included inthose instruments were reflected the following transactions between Dominion and DFV greater than the average market price of the common shares.

and Dominion Telecom:

• Loans from Dominion Telecom and DFV to Dominion of $140 million at December 31, 2002;

11. Available-For-Sale and Other Investment Securities

• Equity losses of $32 million;

• Interest expense on the affiliated loans of $13 million; and Dominion holds marketable debt and equity securities innuclear

• Management and other support services billed by Dominion to decommissioning trust funds, retained interests from prior securiti-Dominion Telecom of $35 million. zations of financial assets and subordinated notes related to cer-tain collateralized debt obligations: These investments are classified as available-for-sale. As described below, prior to

10. Earnings Per Share adopting SFAS No. 143, Dominion did not record unrealized gains and losses inAOCI for investments held for decommissioning its The following table presents the calculation of Dominion's basic utility nuclear plants; those investments are not presented in the and diluted EPS: table below for 2002.

Year Ended December31, 2004 2003 2002 Available-for-sale securities as of December 31:2004 and 2003 (millions, except per share amounts) are summarized below:

Income from continuing operations before cumulative effect of changes inaccounting Total Total principles Unrealized Unrealized

$1264 $ 949 $1,367 Gains Loss from discontinued operations Losses (15) (6421 -

Fair Included Included Cumulative effect of changes inaccounting Value inAOCI inAOCI principles - 1 -

Imillions)

Net income $1249 $ 318 $1,362 2004 Basic EPS Equity securities $,1229 $240 $12 Average shares of common stock Debt securities 1,044 20 1 outstanding-basic 329.1 317.5 281.0 Total 2273 Income from continuing operations before 260 13 cumulative effect of changes inaccounting 2003 principle S 3.84 $ 2.99 $ 4.85 Equity securities 1.092 157 9 Loss from discontinued operations .0.04) . 12.021 - Debt securities 1,102 22 12 Cumulative effect of changes inaccounting Total $2,194 $179 $21 principles - .03 -

Net income S 3.80 S1.00 S 4.85 The following table presents the fair value and gross unrealized Diluted EPS Average shares of common stock -

losses of Domininn's available-for-sale securities, aggregated by outstanding 329.1 317.5 281.0 investment category and the length of time the securities have Net effect of potentially dilutive securities? 1.4 1.3 1.6 been ina continuous loss position, at December 31, 2004:

Average shares of common stock outstanding-diluted 330.5 318.8 282.6 Equity Securities Debt Securities Income from continuing operations before Fair Unrealized Fair Unrealized cumulative effect of changes inaccounting Value Losses Value tosses principles $ 3.82 S 2.98 $ 4.82 (millions)

Loss from discontinued operations (0.04) (2.011 - Less than 12 months S92 $10 $166 S1 Cumulative effect of changes inaccounting 12 months or more 9 2 5 principles - .03 -

Total $101 $12 $171 $1 Net income $ 3.78 S 1.00 $ 4.82 Il) Potentially dilutive securities consist of options, restricted stock, equity-linked securities, contingently convertible senior notes and shares issuable under a forward equity sale agreement.

D 2004/ Page 68

Notes to Consolidated Financial Statements. Continued Debt securities backed by mortgages and loans do not have 12. Property, Plant and Equipment stated contractual maturities as borrowers have the right to call or Major classes of property, plant and equipment and their repay obligations with or without call or prepayment penalties. At respective balances are:

December 31. 2004, these debt securities totaled $335 million. The fair value of all other debt securities at December 31, 2004 by At December 31. 2004 2003 contractual maturity are as follows: - (millions)

Utility Amount Generation $10,135 S 9.780 (millions) Transmission 3,464 3,308 Due inone year or less S18 Distribution 8,024 7,713 Due after one year through five years 230 Storage 1.023 999 Due after five years through ten years 261 Nuclear fuel 795 757 Due after ten years 200 Gas gathering and processing ! 418 416 General 774 795 Total $709 Plant under construction 674 698 Total utility 25.307 24.466 Presented below is selected information regarding the sales of Nonutility investment securities. Indetermining realized gains and losses, the Exploration and production properties being cost of these securities was determined on a specific identification amortized:

Proved 8246 7.561 basis. Unproved 653 567 Unproved exploration and production 2004 2003111 2002 properties not being amortized 970 1,154 (millions) Merchant generation properties-nuclear 997 929 Available-for-sale securities: - Nuclear fuel 271 175 Proceeds from sales $463 $832 $506 Merchant generation properties-other 1268 1,214 Realized gains 57 62 58 Other-including plant under construction 951 1,041 Realized losses 90 102 58 Total nonutility 13,356 12,641 Trading securities: Total property, plant and equipment $38,63 $37,107 Net unrealized gain (losspz) 4 12 O(l0 Ill Beginning in2003. after adopting SFAS No. 143. Dominion accounts for its Costs of unproved properties capitalized under the full cost utility decommissioning trust investments as availabla-for-sale. method of accounting that were excluded from amortization at f21 For 2002. $5million of net realized and unrealized pre-tax losses related to December 31, 2004 and the years inwhich such excluded costs retained interests held by DCIwere reported inearnings. Effective May 1.

2002, Dominion reclassified its retained interests from securitizations from were incurred, are as follows:

trading to available-for-sale based on a determination that the retained interests were not readily marketable on terms that would be acceptable la Total 2004 2003 2002 Years Prior Dominion. imillionsl Property acquisition Decommissioning Trust Investments-Utility Plants 2002 Costs $711 $ 43 $ 60 S 53 $555 Prior to adopting SFAS No: 143, Dominion recognized an expense Exploration custs 122 44 30 25 23 for the future cost of decommissioning its utility nuclear plants Caoitalized interest 137 49 54 25 9 equal to the amounts collected from ratepayers and earnings on; I Total $970 $136 $144 $103 $587 trust investments dedicated to funding the decommissioning of those plants. The trusts were reported at fair value with realized There were no significant properties under development, as and unrealized earnings on the trust investments, as well as an defined by the SEC, excluded from amortization at December 31, offsetting expense to increase the accumulated provision for 2004. As gas and oil reserves are proved through drilling or as decommissioning, recorded as a component of other income (loss). properties are deemed to be impaired, excluded costs and any During 2002, Dominion recognized net realized gains and interest related reserves are transferred on an ongoing, well-by-well basis income of $11 million and net unrealized losses of $67 million into the amortization calculation.

related to the trusts. Amortization rates for capitalized costs under the full cost method of accounting for Dominion's United States and Canadian cost centers were as follows:

Year Ended December 31, 2004 2003 2002 (Per Mcf Equivalentl United States cost center $128 $1.20 $1.13 Canadian cost center 1.18 1.00 0.85 D 2004 1 Page 69

E1 Notes to Consolidated Financial Statements, Continued Volumetric Production Payment Transactions 13. Goodwill and Intangible Assets In 2004, Dominion received $413 million incash for the sale of a Goodwill fixed-term overriding royalty interest in certain of its natural gas There was no impairment of or material change to the carrying reserves for the period May 2004 through April 2008. The sale amount and segment allocation of goodwill in2004.

reduced Dominion's proved natural gas reserves by approximately In 2003, Dominion recorded goodwill impairment charges of 83 billion cubic feet lbcf). While Dominion is obligated under the

$18 million related to the DCI reporting unit. During 2003, a DCI agreement to deliver to the purchaser its portion of future natural subsidiary received an unfavorable arbitration ruling that resulted gas production from the properties, it retains control of the proper-inlower margins for services provided. Another DCI subsidiary ties and rights to future development drilling. If production from experienced delays inexpanding marketing and stabilizing pro-the properties is inadequate to deliver approximately 83 bcf of duction efforts. As a result of these unfavorable developments, natural gas scheduled for delivery to the purchaser, Dominion has Dominion performed goodwill impairment tests, using discounted no obligation to make up the shortfall. Cash proceeds received cash flow analyses, which indicated that the goodwill associated from this VPP transaction were recorded as deferred revenue.

with those entities was impaired.

Dominion will recognize revenue from the transaction as natural Also in2003, as described in Note 9,Dominion purchased the gas is produced and delivered to the purchaser. Dominion also.

remaining equity interest in OFV for $62 million, including $2mil-entered into a VPP transaction in 2003 receiving proceeds of $266 lion for accrued dividends. This transaction was accounted for as a million for approximately 66 bcf for the period August 2003 purchase of a minority interest and $60 million was recognized as through August 2007.

goodwill and immediately impaired. The purchase enabled Sale of British Columbia Assets Dominion to proceed with its strategy to sell DTI.

In December 2004, Dominion sold the majority of its natural gas In2002, Dominion recorded a goodwill impairment charge of and oil assets in British Columbia, Canada, for $476 million, which $13 million related to a DCI subsidiary that received an was credited to Dominion's full cost pool. Dominion received cash unfavorable arbitration ruling that affected its ability to recover proceeds of $320 million in December 2004 and $156 million in disputed amounts for past and future performance under a con-January 2005. The properties sold produced about 30 bcf equiv- tract with a major customer. Dominion performed a goodwill alent net of natural gas annually. Dominion recorded expenses of impairment test, using discounted cash flow analysis, which

$10 million inother operations and maintenance expense related indicated that the goodwill was impaired.

to the sale.

Other Intangible Assets Jointly-Owned Utility Plants All of Dominion's intangible assets, other than goodwill, are sub-Dominion's proportionate share of jointly-owned utility plants at ject to amortization. Amortization expense for intangible assets December 31, 2004 follows: was $62 million, $54 million and $53 million for 2004, 2003 and 2002, respectively. There were no material acquisitions of Bath County North intangible assets in2004 or 2003. Intangible assets are included in Pumped Anna Clover other assets on the Consolidated Balance Sheets. The components Storage Power Power of intangible assets at December 31, 2004 and 2003 were as Station Station Station follows:

Imillions. except percentages)

Ownership interest 60.0% 88.4% 50.0% 2004 2003 Plant in service S 1,014 $ 2,067 $ 548 Gross Gross Accumulated depreciation 378 897 112 Carrying Accumulated Carrying . Accumulated Nuclear fuel - 380 - Amount Amortization Amount Amortization Accumulated amortization of nuclear fuel - 285 - Imillionsl Construction work in Software and progress 27 47 3 software licenses S579 $269 $543 $237 Other 118 30 73 23 Total $697 $299 $616 $260 The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly owned facilities in the same proportion as their respective ownership Annual amortization expense for intangible assets is estimated interest. Dominion reports its share of operating costs in the to be $63 million for 2005, $57 million for 2006, $48 million for appropriate operating expense (fuel, other operations and main- 2007, $33 million for 2008 and $26 million for 2009.

tenance, depreciation, depletion and amortization and other taxes, etc.) inthe Consolidated Statements of Income.

D 2004 /Page 70

Notes to Consolidated Financial Statements, Continued (8) Reported inother current liabilities.

14. Regulatory Assets and Liabilities (91Rates charged to customers by Dominion's regulated businesses include a Dominion's regulatory assets and liabilities include the following: provision for the cost of future activities to remove assets expected to be incurred at the time of retirement.

At December 31, 2004 2003 At December31, 2004,'approximately $416 million of Domin-(millions) ion's regulatory assets represented past expenditures on which it Regulatory assets:

Unrecovered gas costs $ 52 S 55 does not earn a return. These expenditures consist primarily of Regulatory assets-current' - 52 55 unrecovered gas costs, customer bad debts and a portion of deferred fuel costs. Unrecovered gas costs and the ongoing portion Other postretirement benefit costs"l 96 102 Income taxes recoverable through future rates' 250 227 of bad debts are recovered within two years. The previously Deferred cost of fuel used in electric generation 248 335 deferred bad debts will be recovered over a 4-year period.

Regional transmission organization start-up and integration costs(4 , 41 30 Deferred fuel costs were historically recovered within two years; Cost of decommissioning DOEuranium enrichment however, inconnection with the settlement of the 2003 Virginia facilitiesms) 18 27 fuel rate proceeding, Dominion agreed to recover $307 million of Customer bad debtVs6 73 65 Other 62 46 previously incurred costs through June 30, 2007 without a return on unrecovered balances.

Regulatory assets-non-current 788 832 Total regulatory assets $840 $887 Regulatory liabilities:

Amounts payable to customers $ 2 $ 3 15. Asset Retirement Obligations Estimated rate contingencies and refunds(71 13 13 0

Dominion's AROs are primarily associated with the decommissioning Regulatory liabilities-curreny l 15 16 of its nuclear generation facilities, retiring certain natural gas pipe-Provision for future cost of removalls' 595 572 lines and dismantling and removing gas and oil wells and platforms.

Other 15 15 In addition, Dominion has AROs related to its natural gas gathering, Regulatory liabilities-non-current 610 587 storage, transmission and distribution systems, including approx-Total regulatory liabilities $625 $603 imately 2,300 gas storage wells inDominion's underground natural (1) Reported in other current assets.

gas storage network. These obligations result from certain safety (2) Costs recognized in excess of amounts included in regulated rates charged by requirements to be performed at the time any pipeline or storage Dominion's regulated gas operations before rates were updated to reflect the well isabandoned. However, Dominion expects to operate its new method of accounting and the cost related to the accrued benefit obligation recognized as part of Dominion's accounting for its acquisition of CNG.

natural gas gathering, storage, transmission and distribution sys-(3) Income taxes recoverable through future rates resulting from the recognition of tems inperpetuity. Thus, AROs for those assets will not be reflected additional deferred income taxes, not previously recorded under past rate- inDominion's Consolidated Financial Statements until sufficient making practices.

(41 The Federal Energy Regulatory Commission (FERCI has authorized the deferral information becomes available to determine a reasonable estimate of start-up costs incurred by transmission owning companies joining a Regional of the fair value of the activities to be performed. Generally, this will Transmission Organization IRTOI. Dominion has deferred $13 million in start-up occur when expected retirement or abandonment dates for costs associated with the Alliance Regional Transmission Organization (ARTO) and $24 million associated with PJM Interconnection, LLC (PJM) and individual pipelines or storage wells are determined by Dominion's associated carrying costs of $4 million. Dominion expects recovery from operational planning. The changes to Dominion's AROs during 2004 Virginia jurisdictional retail customers to commence at the end of the Virginia were as follows:

retail rate cap period, subject to regulatory approval.

(15 Cost of decommissioning the Department of Energy's uranium enrichment Amount facilities, representing the unamortized portion of Dominion's required contributions. Beginning in 1992, Dominion began making contributions over a (millionsl 15-year period and collecting these costs in electric customers' fuel rates. Asset retirement obligations at December 31, 200311 $1,653 (6) The Public Utilities Commission of Ohio (Ohio Commission) has authorized the Obligations incurred during the period 23 collection of previously deferred costs of $51 million associated with certain Obligations settled during the period (60) uncollectible customer accounts from 2001 over five years through the tracker Accretion expense 91 rider effective in 2004. The Ohio Commission has also authorized the deferral Revisions inestimated cash flows (2) and recovery of excess bad debt costs incurred in 2003 and thereafter for 2 Other certain uncollectible customer accounts not contemplated in current base rate recoveries. The total deferral of 2004 ard 2003 excess uncollectible amounts Asset retirement obligations at December 31, 20040) $1,707 was $17 million and $13 million, respectively.

(7) Estimated rate contingencies and refunds are associated with certain increases (1)Amount includes $2million reported in other current liabilities.

in prices by Dominion's rate regulated utilities and other rate making issues that are subject to final modification in regulatory proceedings.

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Notes to Consolidated Financial Statements, Continued Dominion has established trusts dedicated to funding the future agreements was $1.44 billion, with a weighted average interest decommissioning of its nuclear plants. At December 31. 2004 and rate of 1.20%.

2003 the aggregate fair value of these trusts, consisting primarily At December 31, 2004 and 2003, total outstanding letters of of debt and equity securities, totaled $2.0 billion and $1.9 billion, credit supported by the joint credit facilities were $183 million and respectively. $85 million, respectively.

CNG Credit Facilities InAugust 2004, CNG entered into a $1.5 billion three-year

16. Short-Term Debt and Credit Agreements revolving credit facility that terminates inAugust 2007. This credit Joint Credit Facilities facility isbeing used to support CNG's issuance of commercial InMay 2004 and 2002, Dominion, Virginia Power and CNG entered paper and letters of credit to provide collateral required by into two joint credit facilities that allow aggregate borrowings of counterparties on derivative financial contracts used by CNG in its up to $2.25 billion. The facilities include a $1.5 billion three-year risk management strategies for its gas and oil production. At revolving credit facility that terminates in May 2007 and a $750 December 31, 2004, outstanding letters of credit under this facility million three-year revolving credit facility that terminates in May totaled $555 million. At December 31, 2003, outstanding letters of 2005. Dominion expects to renew the $750 million credit facility credit under the previous facility totaled $820 million.

prior to its maturity in May 2005. These credit facilities are being In addition to the facilities above, in June and August of 2004, used for working capital, as support for the combined commercial CNG entered into two $100 million letter of credit agreements that paper programs of Dominion, Virginia Power and CNG and other terminate inJune 2007 and August 2009, respectively. Addition-general corporate purposes. The $1.5 billion and $750 million ally, in October 2004, CNG entered into three letter of credit credit facilities can also be used to support the issuance of up to agreements totaling $700 million that terminate inApril 2005 and

$500 million and $200 million of letters of credit, respectively. are not expected to be renewed. These five agreements support At December 31, 2004, total outstanding commercial paper letter of credit issuances, providing collateral required on supported by the joint credit facilities was $573 million, with a derivative financial contracts used by CNG in its risk management weighted average interest rate of 2.39%. At December 31, 2003, strategies for gas and oil production. At December 31, 2004, out-total outstanding commercial paper supported by previous credit standing letters of credit under these agreements totaled $900 million.

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Notes to Consolidated Financial Statements, Continued

17. Long-Term Debt 2004 Weighted Average At December 31, Couporili 2004 2003 (millions, except percentages)

Dominion Resources, Inc.:

Unsecured Senior and Medium-Term Notes:

.2.25% to 7.82%, due 2004 to 2008 4.85% S 2,002 $1,740 5.0% to 8.125%. due 2009 to 2033 2) 6.25% 3,880 3,680 Unsecured Equity-Linked Senior Notes, 5.75% to 8.05%, due 2006 to 200831' 5.75% 330 , 743 Unsecured Convertible Senior Notes, 2.125%, due 202341' 220 220 Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% to 8.4%, due 2027 to 2041 8.22% 825 825 Unsecured Nonrecourse Debt, Variable Rate, due 2004 - 18 Consolidated Natural Gas Company:

Unsecured Debentures and Senior Notes:

5.375% to 7.375%. due 2004 to 2008 6.16% 1,000 1,400 5.0% to 6.875%, due 2010 to 2027(2! 6.17% 2,350 1,950 Unsecured Senior Subordinated Debt, 9.25%. due 2004 - 88 Secured Bank Debt, Variable Rate, due 2006(9 . 2.55% 234 234 Unsecured Junior Subordinated Notes Payable to Affiliated Trust, 7.8%, due 2041 206 206 Virginia Electric and Power Company:

Secured First and Refunding Mortgage 8onds:15) 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 Secured Bank Debt, Variable Rate, due 200719)

• 1.75% 370 370 Unsecured Senior and Medium-Term Notes:

5.375% to 7.2%, due 2004 to 2008 5.57% 1,370 1,445 4.50% to 7.25%, due 2010 to 2025 5.08% 936 830 Unsecured Callable and Puttable Enhanced SecuritiessM, 4.10%, due 2038(61 225 225 Tax-Exempt Financings:(7)

Variable Rate, due 2008 1.33% 60 60 Variable Rates, due 2015 to 2027 1.34% 137 137 4.95% to 9.62%, due 2005 to 2008 5.24% 108 107 2.225% to 7.65%, due 2009 to 2031 5.32% 397 295 Unsecured Junior Subordinated Notes Payable to Affiliated Trust, 7.375%, due 2042 412 412 Dominion Energy, Inc.:

Unsecured Medium-Term Notes, 5.72% to 6.1%, due 2005 to 200610) 5.94% 262 243 Unsecured Medium-Term Notes, 4.92%, due 2009(91 191 -

Secured Senior Note, 7.33%, due 2020 231 238 Secured Bank Debt, Variable Rates, due 2006'91 2.55% 347 347 Revolving Lines of Credit, Variable Rates, due 2004 - 150 Dominion Capital, Inc.:

Notes. 12.5%. due 2008 6 6 Dominion Resources Services, Inc., Secured Bank Debt, Variable Rate, due 200619) 2.34% 107 107 Dominion Fiber Ventures, Secured Senior Notes, 7.05%, due 2005(10) - 21 16,933 17,074 Fair value hedge valuationl"" 11 43 Amounts due within one year 6.02% (1,368) (1,252)

Unamortized discount and premium, net (69) (89)

Total long-term debt $15,507 $15,776 (1) Represents weighted-average coupon rates for debt outstanding as of (3) InNovember 2004, Dominion issued 6.7 million shares of its common stock to December 31, 2004. settle stock purchase contracts related to $413 million of 8.05% equity-linked (21 At the option of holders inOctober 2006 and August 2015, $150 million of senior notes. Inconnection with settlement, the senior notes were remarketed CNG's 6.B75% senior notes due 2026 and $510 million of Dominion's 5.25% and now carry an annual interest rate of 3.66%. As a result of settlement of senior notes due 2033, respectively, are subject to redemption at 100% of the the stock purchase contracts, the 3.66% senior notes are reported as a principal amount plus accrued interest. component of Unsecured Senior and Medium-Term Notes.

D 20041 Page 73

Notes to Consolidated Financial Statements, Continued (4) Convertible into acombination of cash and shares of Dominion's common financings are supported by astand-alone $200 million three-year credit stock at any time after March 31, 2004 when the average closing price of facility that terminates inMay 2006.

Dominion common stock reaches $88.32 per share for aspecified period. At (8) Aggregate principal amount of CAD$545 million of securities denominated in the option of holders on December 15, 2006, December 15, 2003. December Canadian dollars and presented inUS dollars, based on exchange rates as of 15, 2013, or December 15, 2018. these securities are subject to redemption at year-end.

100% of the principal amount plus accrued interest. (9) Represents debt associated with certain special purpose lessor entities that are (5) Substantially all of Virginia Power's property ($12.0 billion at December 31, consolidated inaccordance with FIN 46R. The debt isnonrecourse to Dominion 20041 issubject to the lien of the mortgage, securing its mortgage bonds. and issecured by the entities' property, plant and equipment, which totaled (6) On December 15, 2008, $225 million of the 4.10% Callable and Puttable $963 million and $997 million at December 31, 2004 and 2003, respectively.

Enhanced Securitiessm due 203B are subject to redemption a!par plus accrued (10) Debt was redeemed inDecember 2004.

interest, unless holders of related options exercise rights to purchase and (11 Represents changes infair value of certain fixed-rate long-term debt asso-remarket the notes. ciated with fair value hedging relationships.

(7) Certain pollution contrul equipment at Virginia Power's generating facilities has been pledged to support these financings. The variable rate tax-exempt 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:

2005 2006 2007 2008 2009 Thereafter Total (millions. except percentages)

Secured First and Refunding Mortgage Bonds - - $ 215 - - - $ 512 $ 727 Secured Senior Notes $ 8 $ 9 10 $10 $ 11 183 231 Unsecured Senior Notes (including Medium-Term Notes) 1,355 1,774 858 1,009 500 7,046 12,542 Unsecured Callable and Puttable Enhanced SecuritiessM - - - 225 225 Tax-ExemptFinancings 5 5 19 157 114. 401 701 Secured Bank Debt - 688 370 - - - 1,058 Unsecured Junior Subordinated Notes Payable to Affiliated Trusts - - - - - 1.443 1.443 Other - - - 6 - - 6 Total $1,368 $2,476 $1,472 $1,182 $ 625 $9,810 $16,933 Weighted average coupon 6.02% 4.16% 5.02% 5.11% 5.21% 6.27%

Dominion'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 these covenants.

Convertible Securities outstanding used inthe calculation of Dominion's diluted EPS As described in Note 3, Dominion entered into an exchange trans- since the conversion price of $73.60 included inthe notes was action with respect to $219 million of its outstanding contingent greater than the average market price of the shares.

convertible senior notes incontemplation of the transition method The senior notes are convertible by holders into a combination of provided by EITF 04-8. Dominion exchanged the outstanding notes cash and shares of Dominion's common stock under any of the for new notes with a conversion feature that requires that the following circumstances:

principal amount of each note be repaid incash. The notes are (1)the price of Dominion common stock reaches $88.32 per share valued at a conversion rate of 13.5865 shares of common stock per for a specified period;

$1,000 principal amount of senior notes, which represents a con- (2)the senior notes are called for redemption by Dormitniott ot or version price of $73.60. Amounts payable in excess of the principal after December 20, 2006; amount will be paid in common stock. The conversion rate is (3)the occurrence of specified corporate transactions; or subject to adjustment upon certain events such as subdivisions, (4)the credit rating assigned to the senior notes by Moody's is splits, combinations of common stock or the issuance to all below Baa3 and by Standard & Poor's is below BBB- or the common stock holders of certain common stock rights, warrants or ratings are discontinued for any reason.

options and certain dividend increases.

Since none of the conditions have been met, the senior notes The new notes outstanding on December 31, 2004 were are not yet subject to conversion. In2007, Dominion will also begin included inthe diluted EPS calculation retroactive to the date of to pay contingent interest if the average trading price as defined in issuance using the method described inEITF 04-8. Under this the indenture equals or exceeds 120% of the principal amount of method, the number of shares included in the denominator of.the the senior notes. Holders have the right to require Dominion to diluted EPS calculation are calculated as the net shares issuable purchase their senior notes for cash at 100% of the principal plus for the reporting period based upon the average market price for accrued interest in December 2006, 2008, 2013 or 2018, or if the period. This did not result inan increase to the average shares Dominion undergoes certain fundamental changes.

D 2004I Page 74

Notes to Consolidated Financial Statements, Continued Equity-Linked Securities common securities that represent the remaining 3%beneficial owner-In2002 and 2000, Dominion issued equity-linked debt securities, ship interest inthe assets held by the capital trusts, Dominion issued consisting of stock purchase contracts and senior notes. The stock various junior subordinated notes. The junior subordinated notes con-purchase contracts obligate the holders to purchase shares of stitute 100% of each capital trust's assets. Each trust must redeem its Dominion common stock from Dominion by a settlement date, two trust preferred securities when their respective junior subordinated notes years prior to the senior notes' maturity date. The purchase price is are repaid at maturity or if redeemed prior to maturity.

$50 and the number of shares to be purchased will be determined Under previous accounting guidance, Dominion consolidated under a formula based upon the average closing price of Dominion the trusts in the preparation of its Consolidated Financial State-common stock near the settlement date. The senior notes, or ments. Inaccordance with FIN 46R, Dominion ceased to con- .

treasury securities insome instances, are pledged as collateral to solidate the trusts as of December 31, 2003 and instead reports as secure the purchase of common stock under the related stock pur- long-term debt on its Consolidated Balance Sheet the junior sub-chase contracts. The holders may satisfy their obligations under the ordinated notes issued by Dominion and held by the trusts..

stock purchase contracts by allowing the senior notes to be remar- The following table provides summary information about the keted with the proceeds being paid to Dominion as consideration for trust preferred securities and Junior subordinated notes out-the purchase of stock. Alternatively; holders may choose to continue standing as of December 31, 2004:

holding the senior notes and use other resources as consideration for the purchase of stock under the stock purchase contracts. Trust Preferred Common Dominion makes quarterly interest payments on the senior notes Date Capital Securities Securities and quarterly payments on the stock purchase contracts at the rates Established Trusts Units Rate Amount Amount described below. Dominion has recorded the present value of the (thousands) Imillions) stock purchase contract payments as a liability, offset by a charge to December Dominion common stock inshareholders' equity. Interest payments on the senior 1997 Resources Capital notes are recorded as interest expense and stock purchase contract Trust FlU 250 7.83% $250 $8 payments are charged against the liability. Accretion of the stock January Dominion purchase contract liability is recorded as interest expense. In 2001 Resources Capital calculating diluted EPS, Dominion applies the treasury stock method to Trust 11(2I 12,000 8.4% 300 9 the equity-linked debt securities. These securities did not have a sig- January Dominion nificant effect on diluted EPS for 2003. 2001 Resources Capital Under the terms of the stock purchase contracts, Dominion Trust 111(3) 250 8.4% 250 8 issued 6.7 million shares of its corrmmon stock in November 2004 October Dominion and will issue between 4.1 million and 5.5 million shares of its 2001 CNG Capital Trust I) 8,000 7.8% 200 6 common stock inMay 2006. Sufficient shares of Dominion August Virginia common stock have been reserved for issuance inconnection with 2002 Power the May 2006 stock purchase contracts. Capital Trust 115 16,000 7.375% 400 12 Selected information about Dominion's equity-linked debt securities ispresented below:

Junior subordinated notes/debentures held as assets by each capital trust were as Senior Stock follows:

Total Notes Purchase Stock Maturity 11l$258 million-Dominion Resources, Inc. 7.83% Debentures due 12/11/2027.

Total Lcng- Annual Contract Total Purchasa of 121 $309 million-Dominion Resources, Inc. 8.4% Debeitures due 1/3012041.

Date of Units Net term Interest Annual Equity Settlement Senior 131 $258 million-Dominion Resources, Inc. 8.4% Debentures due 1/1512031.

Issuance Issued Proceeds Debt Rate Rate Charge Date Notes 1415206 million-CNG 7.8% Debentures due 10/31/2041.

• millions, eucept percentages) 151 5412 million-Virginia Fower 7.375% Debentures due 7/30/2042.

2000 8.3 S400.1 S412.5 3.66%t" -%2t S20.7 11/04 11/06 2002 6.6 $320.1 S330.0 5.75% 3.30% $36.3 5/06 5/08 Distribution payments on the trust preferred securities are consid-ered to be fully and unconditionally guaranteed by the respective (1 Prior to their remarketing in November 2004, the senior notes carried an annual parent company that issued the debt instruments held by each trust, interest rate of 8.05%. when all of the related agreements are taken into consideration. Each 121 The stock purchase contracts carried an annual interest rate of 1.45% prior to guarantee agreement only provides for the guarantee of distribution their settlement in November 2004.

payments on the relevant trust preferred securities to the extent that Junior Subordinated Notes Payable to Affiliated Trusts the trust has funds legally and immediately available to make dis-From 1997 through 2002, Dominion established five subsidiary capital tributions. The trust's ability to pay amounts when they are due on the trusts, each as a finance subsidiary of the respective parent company, trust preferred securities issolely dependent upon the payment of which holds 100% of the voting interests. The capital trusts sold trust amounts by Dominion, Virginia Power or CNG when they are due on preferred securities representing preferred beneficial interests and 97% the junior subordinated debt instruments. If the payment on the junior beneficial ownership in the assets held by the capital trusts. In exchange subordinated notes isdeferred, the company that issued them may not for the funds realized from the sale of the trust preferred securities and make distributions related to its capital stock, including dividends, D 2004 / Page 75

Notes to Consolidated Financial Statements, Continued redemptions, repurchases, liquidation payments or guarantee pay- Presented below are the series of Virginia Power preferred ments. Also, during the deferral period, it may not make any payments stock not subject to mandatory redemption that were outstanding or redeem or repurchase any debt securities that are equal inright of as of December 31, 2004:

payment with, or subordinated to, the junior subordinated notes.

Issued and Outstanding Entitled Per Share Dividend Shares upon Liquidation

18. Subsidiary Preferred Stock (thousands)

S5.00 . 107 112.50 Dominion is authorized to issue up to 20 million shares of preferred 4.04 13 102.27 stock. During 2001, Dominion issued 665,000 shares of Series A, 4.20 15 102.50 4.12 32 103.73 mandatorily convertible preferred stock, liquidation preference 4.0- 73 101.00

$1,000 per share, to Piedmont Share Trust (Piedmont Trust) in 7.05 500 103.1811) 6.98 600 103.1152 connection with the formation of OFV and the issuance of senior Flex MMP 12/02, Series A 1,250 . . 100.00 notes by DFV. Dominion was the beneficial owner of the Piedmont Total 2.590 Trust, which was consolidated inthe preparation of Dominion's Consolidated Financial Statements, thus eliminating the out- (1)Through 7/31/05; $102.82 commencing 8/1/05; amounts decline insteps there-standing shares of preferred stock. During 2004, as a result'of the after to $100.00.

retirement of DFV's senior notes, the Piedmont Trust was dissolved 121 Through 8/31/05; $102.80 commencing 9/1/05; amounts decline insteps there-after to $100.00.

and the outstanding shares of preferred stock were retired.

Virginia Power is authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference. Upon involuntary liquidation, dissolution or winding-up of Virginia Power, each share 19. Shareholders' Equity is entitled to receive $100 per share plus accrued dividends. Divi- Issuance of Common Stock dends are cumulative. During 2004, Dominion issued 14 million shares of common stock Holders of the outstanding preferred stock of Virginia Power are and received proceeds of $839 million. Of this amount, 7 million not entitled to voting rights except under certain provisions of the shares and proceeds of $413 million resulted from the settlement of amended and restated articles of incorporation and related provi- stock purchase contracts associated with Dominion's 2000 issuance sions of Virginia law restricting corporate action, or upon default in of equity-linked debt securities. Net proceeds were used for general dividends, or inspecial statutory proceedings and as required by corporate purposes, principally repayment of debt. The remainder of Virginia law (such as mergers, consolidations, sales of assets, dis- the shares issued and proceeds received in2004 occurred through solution and changes invoting rights or priorities of preferred stock). Dominion Directs (adividend reinvestment and open enrollment In2002, Virginia Power issued 1,250 units consisting of 1,000 shares direct stock purchase plan), employee savings plans and the exercise per unit of cumulative preferred stock for $125 million. The preferred of employee stock options. In2005, Dominion DirectO and the stock has adividend rate of 5.50% until the end of the initial dividend Dominion employee savings plans will purchase Dominion common period on December 20,2007. The dividend rate for subsequent periods stock on the open market with the proceeds received through these will be determined according to periodic auctions. Except during the programs, rather than having additional new common shares issued.

initial dividend period, and any non-call period, the preferred stock will Repurchases of Common Stock be redeemable, inwhole or inpart, on any dividend payment date at the InJuly 1998, Dominion was authorized by its Board of Directors to option of Virginia Power. Virginia Power may also redeem the preferred repurchase up to the lesser of 16.5 million shares, or $650 mrilhion cf its stock, inwhole but not inpart, if certain changes are made to federal tax outstanding common stock. As of December 31, 2004, Dominion had law which reduce the dividends received deduction percentage.

repurchased approximately 12 million shares for $537 million, with its last repurchase occurring in2002. InFebruary 2005, inorder to recog-nize the significant increase inthe size of the company and the market value of its common stock since the time of the previous authorization, Dominion's Board of Directors superseded this authority, with new authority, to repurchase up to the lesser of 25 million shares or $2.0 billion of Dominion's outstanding common stock.

D 2004/ Page 76

Notes to Consolidated Financial Statements, Continued Forward Equity Transaction proceeds are not needed, Dominion has the option to either cash settle InSeptember 2004, Dominion entered into a forward equity sale or net share settle the remainder of the second tranche of the forward agreement (forward agreement) with Merrill Lynch International (MLI), agreement inwhole, or inpart, and may elect settlement earlier than the as forward purchaser, relating to 10 million shares of Dominion's stated maturity date. If Dominion elects to cash or net share settle any common stock. The forward agreement provides for the sale of two portion of the remainder of the second tranche, the payment isbased on tranches of Dominion common stock, each with stated maturity dates the difference between Dominion's share price and the applicable and settlement prices. Inconnection with the forward agreement, MLI forward sale price for the second tranche, multiplied by the number of borrowed an equal number of shares of Dominion's common stock shares being settled.

from stock lenders and, at Dominion's request, sold the borrowed If,at December 31,2004, Dominion had elected a cash settlement of .

shares to J.P. Morgan Securities Inc. (JPM) under a purchase agree- the 8 million shares inthe second tranche, Dominion would have owed ment among Dominion, MLI and JPM. JPM subsequently offered the MLl $28 million, of which, $18 million would have represented settle-borrowed shares to the public. Dominion accounted for the forward ment of the 5 million shares remaining inthe second tranche after the agreement as equity at its initial fair value but did not receive any' February 2005 settlement If,at the time of cash settlement Dominion's proceeds from the sale of the borrowed shares. current share price were lower than the forward sale price, Dominion The use of a forward agreement allows Dominion to avoid equity would receive a payment from MLI. For every dollar increase (decrease) market uncertainty by pricing a stock offering under then existing market inthe value of Dominion's stock, the value of the settlement of the conditions, while mitigating share dilution by postponing the issuance of shares remaining inthe second tranche from MLI's perspective would stock until funds are needed. Except inspecified circumstances or events increase (decrease) by $5million.

that would require physical share settlement, Dominion may elect to Dominion expects to use proceeds received from physical share settle the forward agreement by means of a physical share, cash or net settlements under the remainder of the second tranche of the forward share settlement and may also elect to settle the agreement inwhole, or agreement to fund part of the cost of acquiring the Kewaunee nuclear inpart earlier than the stated maturity date at fixed settlement prices. power plant inWisconsin for $220 million (which is expected to close in Under either a physical share or net share settlement the maximum the first half of 2005) and the acquisition of three electric generating number of shares deliverable by Dominion under the terms of the for- stations from USGen for $642 million (which closed on January 1,2005).

ward agreement was limited to the 10 million shares specified inthe Shares Reserved for Issuance two tranches. Assuming gross share settlement of all shares under the At December 31, 2004, Dominion had a total of 47 million shares forward agreement, Dominion would have received aggregate proceeds reserved and available for issuance for the following: Dominion of approximately $644 million, based on maturity forward prices of

• Directs, employee stock awards, employee savings plans, director

$64.62 per share for the 2 million shares included inthe first tranche and stock compensation plans, stock purchase contracts associated

$64.34 per share for the 8million shares included inthe second tranche.

with equity-linked debt securities and a forward equity sale However, Dominion elected to cash settle the first tranche in agreement.

December 2004 and made a payment to MLI for $5.8 million, representing the difference between Dominion's share price and the Accumulated Other Comprehensive Income (Loss) applicable forward sale price, multiplied by the 2 million shares. Presented inthe table below is a summary of AOCI by component:

Dominion recorded the settlement payment as a reduction to common At December31, 2004 2003 stock inits Consolidated Balance Sheet. Additionally, Dominion elected to cash settle 3 million shares of the second tranche inFebruary 2005 (millions)

Net unrealized losses on derivatives-hedging and made e payment to MLI for $17.4 million. activities . $(1,181) $(768)

The remaining 5 million shares of the second tranche must be settled Net unrealized gains on investment securities 149 89 by May 17,2005. If gross share settlement were elected for the Minimum pension liability adjustment 114) 114)

Foreign currency translation adjustments 50 64 remainder of th6 second tranche at its maturity date, Dominion would receive aggregate proceeds of approximately $322 million and would Total accumulated other comprehensive loss $ (996) $(629) deliver 5 million of its common shares. Inthe event any or all of the D 20041 Page 77

ffi.

Notes to Consolidated Financial Statements, Continued Stock-Based Awards During 2004,2003 and 2002, respectively, Dominion granted approx-The following table provides a summary of changes in amounts of imately 582,000 shares, 402,000 shares, and 14,000 shares of restricted Dominion stock options outstanding as of and for the years ended stock with weighted-average fair values of $63.29, $56.08 and $60.62.

December 31, 2004, 2003 and 2002. Generally; the exercise price of Dominion employee stock options equals the market price of

20. Dividend Restrictions Dominion common stock on the date of grant.

The 1935 Act and related regulations issued by the SEC impose Weighted- Weighted-Stock average average restrictions on the transfer and receipt of funds by a registered holding Options Exercise Price FairValue company from its subsidiaries, including a general prohibition against (thousands) loans or advances being made by the subsidiaries to benefit the regis-Outstanding at December tered holding company. Under the 1935 Act, registered holding 31.2001 20,992 $52.90 companies and their subsidiaries may pay dividends only from retained Exercisable at December

31. 2001 7.955 42.68 earnings, unless the SEC specifically authorizes payments from other capital accounts. Dominion received dividends from its subsidiaries of Granted-2002 3,122 $62.28 $10.91 Exercised, cancelled and $1.2 billion, $1.1 billion and $945 million in2004,2003 and 2002, forfeited 13.057) $44.54 respectively.

Outstanding at December At December 31, 2004, Dominion's consolidated subsidiaries had

31. 2002 21,057 $55.49 approximately $9.3 billion incapital accounts other than retained eamings, Exercisable at December 31,2002 8,586 $47.95 representing capital stock, other paid incapital and AOCI. Dominion Exercised, cancelled and Resources, Inc. had approximately $10.0 billion incapital accounts other forfeited 12,513) $44.39 than retained earnings at December 31, 2004. Generally, such amounts are Outstanding at December not available for the payment of dividends by affected subsidiaries, or by 31, 2003 18.544 $56.97 Dominion itself, without specific authorization by the SEC.

Exercisable at December Inresponse to a Dominion request, the SEC granted relief in2000, 31, 2003 11.604 $54.44 authorizing payment of dividends by CNG from other capital accounts Exercised, cancelled and forfeited 14,736) $47.67 to Dominion inamounts up to $1.6 billion, representing CNG's retained earnings prior to Dominion's acquisition of CNG. The SEC granted Outstanding at December 31,2004 13,808 S60.17 further relief in2004, authorizing Dominion's nonutility subsidiaries to Exercisable at December pay dividends out of capital or unearned surplus insituations where 31, 2004 10,768 560.01 such subsidiary has received excess cash from an asset sale, engaged ina restructuring, or isreturning capital to an associate company.

There were no options granted in2003 or 2004. The fair value Dominion's ability to pay dividends on its common stock at declared of the options granted in2002 were estimated on the dates of rates was not impacted by the restrictions discussed above during grant using the Black-Scholes option pricing model with the 2004, 2003 and 2002.

following weighted-average assumptions: The Virginia State Corporation Commission (Virginia Commis-2002 sion) may prohibit any public service company, including Virginia Expected dividend yield 4.17% Power, from declaring or paying a dividend to an affiliate, if found Expected volatility 22.67% not to be in the public interest. At December 31, 2004, the Virginia Risk free interest rate 4.38% Commission had not restricted the payment of dividends by Contractual life 10 years Expected life 6years Virginia Power.

Certain agreements associated with Dominion's credit facilities The following table provides certain information about stock contain restrictions on the ratio of debt to total capitalization. These options outstanding as of December 31, 2004: limitations did not restrict Dominion's ability to pay dividends or receive dividends from its subsidiaries at December 31, 2004.

Options Outstanding Options Exercisable See Note 17 for a description of potential restrictions on dividend Weighted-average Weighted- Weighted- payments by Dominion and certain subsidiaries inconnection with Remaining average average the deferral of distribution payments on trust preferred securities.

Exercise Shares Contractual Exercise Shares Exercise Price Outstanding Life Price Exercisable Price (thousands) (years) (thousands)

21. Employee Benefit Plans 50-519.99 2 4.0 519.10. 2 519.10

$20-G30.99 24 4.1 524.88 24 $24.88 Dominion and its subsidiaries provide certain benefits to eligible active

$31-540.99 30 5.0 $39.25 30 $39.25 541-550.99 1,318 5.7 545.99 1,192 545.50 employees, retirees and qualifying dependents. Under the terms of its 551-460.99 8,021 4.2 $59.91 5,924 $59.90 benefit plans, Dominion and its subsidiaries reserve the right to change, 561-569 4,413 6.4 $65.23 3.596 $65.41 modify or terminate the plans. From time to time inthe past, benefits Total 13,808 5.0 $60.17 10,768 $60.01 have changed, and some of these changes have reduced benefits.

D 2004/ Page 78

Notes to Consolidated Financial Statements, Continued Dominion maintains qualified noncontributory defined benefit . The Medicare Act introduces a prescription drug benefit under Medicare pension plans covering virtually all employees. Retirement benefits are (Medicare Part D)as well as a federal subsidy to sponsors of retiree based primarily on years of service, age and compensation. Dominion's health care benefit plans that provide a benefit that isat least actuarially funding policy isto generally contribute annually an amount that isin equivalent to Medicare Part D.Based on an analysis performed by a accordance with the provisions of the Employment Retirement Income third party actuary, Dominion has determined that the prescription drug Security Act of 1974. The pension program also provides benefits to benefit offered under its other postretirement benefit plans isat least certain retired executives under company-sponsored nonqualified actuarially equivalent to Medicare Part Dand therefore expects to employee benefit plans. Certain of these nonqualified plans are funded receive the federal subsidy offered under the Medicare Act. Dominion through contributions to a grantor trust. expects toreceive subsidies of approximately $4million annually during Dominion provides retiree health care and life insurance benefits the period 2006 through 2009 and expects to receive approximately $26 with annual premiums based on several factors such as age, retirement million during the period 2010 through 2014. Dominion considered the date and years of service. In2004, Dominion adopted a plan to amend its passage of the Medicare Act a significant event requiring remeasure-non-union retiree health care and life insurance plans. Inconnection with ment of its APBO on December 8,2003. Dominion will amortize the the amendment eligible employees under age fifty-five share more of unrecognized actuarial gains associated with the benefits of the subsidy the costs of benefits with Dominion, and certain retiree medical benefits over the average remaining service period of plan participants in were enhanced. Dominion re-measured its accumulated postretirement accordance with SFAS No. 106. Dominion uses December 31 as its benefit obligation during the third quarter of 2004 and as a result measurement date for virtually all of its employee benefit plans.

reduced the liability by $59 million. The impact of re-measurement on Dominion uses a market-related value of pension plan assets to the 2004 postretirement net periodic benefits cost was not material. determine the expected return on pension plan assets, a component of Dominion will amortize the unrecognized actuarial gains associated with net periodic pension cost The market-related value recognizes changes the plan amendment over the average remaining service period of plan infair value on astraight-line basis over a four-year period. Changes in participants inaccordance with SFAS No. 106, Empioyers'Accounting fair value are measured as the difference between the expected and for PostretirementBenefits Other Than Pensions actual plan asset returns, including dividends, interest and realized and On December 8,2003, the Medicare Prescription Drug, Improvement unrealized investment gains and losses.

and Modemization Act of 25O3 (tne Medicare Act) was signed into law.

The following tables summarize the changes inDominion's pension and other postretirement benefit plan obligations and plan assets and a statement of the plans' funded status:

Other Postretirement Pension Benefits Benefits Year ended December 31. 2004 2003 2004 2003 Imillions)

Change in benefit obligation:

Benefit obligation at beginning of year $3,110 $2,799 S1,351 $1,119 Service cost 97 86 63 55 Interest cost .. 190 182 83 79 Benefits paid (143) 1159) (68) (601 Actuarial loss drirng the year 143 200 11 228 Actuarial gain related to Medicare Part D - - - (701 Plan amendments 13 2 (59)

Benefit obligation at end of year 3,410 3,110 1,381 1,351 Change in plan assets:

Fair value of plan assets at beginning of year 3,734 3,074 587 443 Actual return on plan assets 453 627 60 89 Contributions 5 192 85 87 Benefits paid from plan assets 1143) (159) (35) (32)

Fair value of plan assets at end of year 4,049 3,734 697 587 Funded status i39 624 (684) 1764)

Unrecognized net actuarial loss 1,225 1,244 366 392 Unrecognized prior service cost 28 18 (7) 4 Unrecognized net transition (asset) obligation - - 27 82 Prepaid (accrued) benefit cost $1,892 $1,886 S (298) 51286)

Amounts recognized inthe Consolidated Balance Sheets at December 31:

Prepaid pension cost $1,947 $1,939 - -

Accrued benefit liability 194) 186) $ (298) $1286)

Intangible asset Is 9 Accumulated other comprehensive loss 24 24 - -

Net amount recognized $1892 $1,886 $ 1298) $12861 D 20041Page 79

Notes to Consolidated Financial Statements, Continued The accumulated benefit obligation for all defined benefit pension The following benefit payments, which reflect expected future plans was $3.0 billion and $2.7 billion at December 31, 2004 and 2003, service, as appropriate, are expected to be paid:

respectively. Under its funding policies, Dominion evaluates plan Other funding requirements annually, usually inthe third quarter after Pension Postretirement receiving updated plan information from its actuary. Based on the Benefits Benefits funded status of each plan and other factors, the amount of con- Imillions) tributions for the current year, if any, isdetermined at that time. 2005 $ 152 $ 70 2006 175 75 Included above are nonqualified and supplemental pension. 2007 155 . B0 plans that do not have 'plan assets' as defined by generally 2008 160 84 accepted accounting principles. The total projected benefit obliga- 2009 165 B9 2010-2014 1,108 528 tion for these plans was $112 million and $99 million at December

31. 2004 and 2003, respectively. The total accumulated benefit Dominion's overall objective for investing its pension and other obligation for these plans was $97 million and $90 million at postretirement plan assets isto achieve the best possible long-term December 31, 2004 and 2003, respectively. Because the accumu- rates of return commensurate with prudent levels of risk. To minimize lated benefit obligation relating to these plans is inexcess of the risk funds are broadly diversified among asset classes, investment fair value of plan assets, Dominion recognized an additional strategies and investment advisors. The strategic target asset allocation minimum liability of $39 million and $34 million at December 31, for Dominion's pension fund is45% U.S. equity securities: 8%non-U.S.

2004 and 2003, respectively. equity securities; 22% debt securities; and 25% other, such as real estate and private equity investments. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities. Dominion's pension plans and other postretirement plans asset allocations at December 31, 2004 and 2003 are as follows:

Pension Plans Other Postretirement Plans Year Ended December 31, 2004 2003 . 2004 2003 Fair  % of Fair %of Fair %of Fair %of Value Total Value Total Value Total Value Total Imillionsl Equity securities:

U.S. 51,761 44 51.658 44 $308 44 5251 43 International 522 13 407 11 74 11 62 11 Debt securities 947 23 859 23 250 36 205 35 Real estate 298 7 264 7 17 2 14 2 Other 521 13 546 15 48 7 55 9 Total $4,043 100 53.734 100 $697 100 $587 100 The components of the provision for net periodic benefit cost were as foKows:

Pension Benefits Other Postretirement Benefits YearEndedDecember31. 2004 2003 2002 2004 2003 2002 Imiltions)

Servicecost . $97 86 $77 $ 63 S 55 $44 interestcosi 190 182 177 83 79 68 Expected return on plan assets (336) 1332) 13491 (44) (33) 1341 Amortization of prior service cost 2 2 1 - 1 Amortization of transition obligation - (2) (41 7 9 11 Amortization of net loss 56 20 2 21 20 5 Net periodic benefit cost Icreditl $ 9 $ 441 S (961 $130 $130 $95 Significant assumptions used indetermining the net periodic cost recognized inthe Consolidated Statements of Income were as follows, on a weighted-average basis:

Pension Benefits Other Postretirement Benefits 2004 2003 2002 2004 2003 2002 Discount rate 6.25% 6.75% 7.25% 6.25% 6.75% 7.25%

Expected return on plan assets 8.75% 8.75% 9.50% 7.79% 7.78% 7.82%

Rate of increase for compensation 4.70% 4.70% 4.60% 4.70% 4.70% 4.60%

Medical cost trend rateld 9.00% 9.00% 9.00%

111Decreasing toa5.0% in2008 andyears thereafter.

D 2004/ Page8O

Notes to Consolidated Financial Statements, Continued Significant assumptions used indetermining the projected remaining subsidiaries do not prefund postretirement benefit costs pension benefit and postretirement benefit obligations recognized but instead pay claims as presented.

inthe Consolidated Balance Sheets were as follows, on a weighted-average basis:

• Other

22. Commitments and Contingencies Pension Postretirement As the result of issues generated in the ordinary course of busi-Benefits Benefits ness, Dominion and its subsidiaries are involved inlegal, tax and 2004 2003 2004 2003 regulatory proceedings before various courts, regulatory commis-Discount rate 6.000/O 6.25% 6.00% 6.25% sions and governmental agencies, some of which involve sub-Rate of increase for compensation 4.70%/o 4.70% 4.70% 4.70% stantial amounts of money. Management believes that the final disposition of these proceedings will not have a material effect on Dominion determines the expected long-term rates of return on Dominion's financial position, liquidity or results of operations:

plan assets for pension plans and other postretirement benefit Long-Term Purchase Agreements plans by using a combination of: Unconditional purchase obligations as defined by accounting

• Historical return analysis to determine expected future risk standards are those long-term commitments that are non-premiums; cancelable or cancelable only under certain conditions, and that

• Forward-looking return expectations derived from the yield on third parties have used to secure financing for the facilities that long-term bonds and the price earnings ratios of major stock will provide the contracted goods or services. Presented below is a market indices; summary of Dominion's agreements as of December 31, 2004:

• Expected inflation and risk-free interest rate assumptions; and 2005 2006 2007 2008 2009 Thereafter Total

• The types of investments expected to be held by the plans.

Imillionsl Assisted by an independent actuary, management develops Purchased electric assumptions, which are then compared to the forecasts of other capacity1) $509 $496 $472 $440 $418 $3,103 $5,438 Production handling for gas independent investment advisors to ensure reasonableness. An and oil production internal committee selects the final assumptions. operationsm 56 54 51 38 23 27 249 Discount rates are determined from analyses performed by a third.

party actuarial firm of AA1Aa rated bonds with cash flows matching (ll commitments represent estimated amounts payable for capacity under power purchase contracts with qualifying facilities and independent power producers.

the expected payments to be made under Dominion's plans. capacity payments under the contracts are generally based on fixed dollar Assumed health care cost trend rates have a significant effect amounts per month, subject to escalation using broad-based economic indices, on the amounts reported for the health care plans. A one- and payments for energy are based on the applicable pricing times the units of percentage-point change inassumed health care cost trend rates electrical energy delivered. At December 31, 2004. the present value of the total commitment for capacity payments is$3.4 billion. capacity payments totaled $570.

would have had the following effects: million, $611 million and $661 million, and energy payments totaled $293 million, Other $289 million and $219 million for 2004, 2003, and 2002, respectively.

Postretiremen, (21Payments under this contract, totaled $22 million and 510 million in2004 and Benefits 2003, respectively. No payments were made under this contract in2002.

One .One

- percentage - - percentage In2004. Dominion paid $153 million incash and assumed $213 point point million of debt inconnection with the termination of three long-term increase decrease power purchase agreements and the acquisition of the related (millionsl generating facilities used by non-utility generators to provide elec-Effect on total service and interest tricity to Dominion. Inconnection with the termination of the agree-cost components for 2004 5 22 $1211 Effect on postretirement benefit ments, Dominion recorded after-tax charges totaling $43 million.

obligation at December 31,2004 $173 $(1411 These charges include the reversal of a $167 million pre-tax contract liability associated with one of the terminated agreements. The Inaddition, Dominion sponsors defined contribution thrift-type contract liability represented the remaining balance of the fair value savings plans. During 2004, 2003 and 2002, Dominion recognized recorded inOctober 2003 upon adoption of SFAS No. 133

$29 million, $27 million and $26 million, respectively, as con- Implementation Issue No. C20, Interpretationof the Meaning of "Not tributions to these plans. Clearly and Closely Related inParagraph 10(b) regarding Contracts Certain regulatory authorities have held that amounts recov- with a Price Adjustment Feature, (Issue C20). The power purchase ered in utility customers' rates for other postretirement benefits, in agreement, which contained pricing terms linked to a broad market excess of benefits actually paid during the year, must be deposited index, had to be recorded at fair value upon adoption of Issue C20; intrust funds dedicated for the sole purpose of paying such bene- however, since it qualified as a normal purchase and sale contract fits. Accordingly,-certain subsidiaries fund postretirement benefit no further changes inits fair value were recognized. In2003, costs through Voluntary Employees' Beneficiary Associations. The D 2004/ Page 81

Notes to Consolidated Financial Statements, Continued Dominion paid $154 million for the purchase of a generating facility Environmental Matters' and the termination of two long-term power purchase agreements Dominion issubject to costs resulting from a steadily increasing with non-utility generators. Dominion recorded after-tax charges number of federal, state and local laws and regulations designed totaling $65 million for the termination of the long-term power to protect human health and the environment. These laws and purchase agreements. Dominion allocates the purchase price to the regulations can result in increased capital, operating and other assets and liabilities acquired and the terminated agreements based costs as a result of compliance, remediation, containment and on their estimated fair values as of the date of acquisition. monitoring obligations.

In the fourth quarter of 2004, Dominion recorded a $112 million Historically, Dominion recovered such costs arising from regu-after-tax charge related to its interest ina long-term power tolling lated electric operations through utility rates. However, to the contract with a 551 megawatt combined cycle facility located in extent environmental costs are incurred in connection with oper-Batesville, Mississippi. Dominion decided to divest its interest inthe ations regulated by the Virginia State Corporation Commission long-term power tolling contract inconnection with its reconsidera- during the period ending December 31, 2010, inexcess of the level tion of the scope of certain activities of the Dominion Energy Clear- currently included inVirginia jurisdictional rates, Dominion's inghouse, including those conducted on behalf of Dominion's results of operations will decrease. After that date, Dominion may business segments, and its ongoing strategy to focus on business seek recovery through rates of only those environmental costs activities within the MAIN to Maine region. The charge is based on related to transmission and distribution operations.

Dominion's evaluation of preliminary bids received from third parties, Superfund Sites-from time to time, Dominion may be identified reflecting the expected amount of consideration that would be as a potentially responsible party to a Superfund site. The Environ-required by a third party for its assumption of Dominion's interest in mental Protection Agency (EPA) (or a state) can either (a)allow such a the contract inthe first quarter of 2005. party to conduct and pay for a remedial investigation, feasibility study and remedial action or (b)conduct the remedial investigation and Lease Commitments. action and then seek reimbursement from the parties. Each party can Dominion leases various facilities, vehicles and equipment be held jointly, severally and strictly liable for all costs. These parties under both operating and capital leases. Payments under certain can also bring contribution actions against each other and seek leases are escalated based on an index such as the consumer price reimbursement from their insurance companies. As a result, Dominion index. Future minimum lease payments under noncancelable may be responsible for the costs of remedial investigation and actions operating and capital leases that have initial or remaining lease under the Superfund Act or other laws or regulations regarding the terms in excess of one year as of December 31, 2004 are as fol- remediation of waste. Dominion does not believe that any currently lows (inmillions): identified sites will result insignificant liabilities.

2005 2006 2007 2008 2009 Thereafter Total In 1987, the EPA identified Dominion and a number of other

$133 $117 $108 $97 $87 $365 $907 entities as Potentially Responsible Parties (PRPs) at two Superfund sites located in Kentucky and Pennsylvania. In 2003, the EPA Rental expense totaled $123 million, $105 million and issued its Certificate of Completion of remediation for the Ken-

$98 million for 2004, 2003 and 2002, respectively, the majority of tucky site. Future costs for the Kentucky site will be limited to which is reflected inother operations and maintenance expense. minor operations and maintenance expenditures. Remediation design isongoing for the Pennsylvania site, and total remediation Dominion has an agreement with a voting interest entity (lessor) costs are expected to be inthe range of $13 million to $25 million.

to lease the Fairless power station inPennsylvania (Fairless), which Based on allocation formulas and the volume of waste shipped to began commercial operations inJune 2004. During construction, the site, Dominion has accrued a reserve of $2million to meet its Dominion acted as the construction agent for the lessor, conti oiled obligations at these two sites. Based on a financial assessment of the design and construction of the facility and has since been the PRPs involved at these sites, Dominion has determined that it reimbursed for all project costs advanced to the lessor. Project costs is probable that the PRPs will fully pay their share of the costs.

totaled $898 million at DecEmber 31, 2004. Dominion will Make Dominion generally seeks to recover its costs associated with annual lease payments of $53 million, which are reflected inthe environmental remediation from third party insurers. At lease commitments table above. The lease expires in2013 aid at December 31, 2004, any pending or possible claims were not that time, Dominion may renew the lease at negotiated amounts recognized as an asset or offset against such obligations.

based on original project costs and current market conditions, sub- Other EPA Matters-In relation to a Notice of Violation ject to lessor approval; purchase Fairless at its original construction received by Virginia Power in2000 from the EPA, Dominion cost: or sell Fairless, on behalf of the lessor, to an independent third entered into a Consent Decree settlement in 2003 and committed party. If Fairless is sold and the proceeds from the sale are less than to improve air quality. Dominion has already incurred certain its original construction cost, Dominion would be required to make a capital expenditures for environmental improvements at its coal-payment to the lessor inan amount up to 70.75% of original project fired stations inVirginia and West Virginia. Dominion continues to costs adjusted for certain other costs as specified inthe lease. The commit to additional measures inits current financial plans and lease agreement does not contain any provisions that involve credit capital budget to satisfy the requirements of the Consent Decree.

rating or stock price trigger events.

D 2004 / PageB2

Notes to Consolidated Financial Statements, Continued Other-Before being acquired by Dominion in2001, Louis Dreyfus The NRC requires that the proceeds from this insurance be used first Natural Gas Corp. (Louis Dreyfus) was one of numerous defendants ina to return the reactor to and maintain it ina safe and stable condition lawsuit consolidated and pending inthe 93rd Judicial District Court in and second to decontaminate the reactor and station site inaccord-Hidalgo County, Texas. The lawsuit alleges that gas wells and related ance with a plan approved by the NRC. Dominion's nuclear property pipeline facilities operated by Louis Dreyfus and facilities operated by insurance is provided by the Nuclear Electric Insurance Limited other defendants caused an underground hydrocarbon plume in (NEIL), a mutual insurance company, and issubject to retrospective McAllen, Texas. The plaintiffs claim that they have suffered damages, premium assessments inany policy year inwhich losses exceed the including propertydamage and lost profits, as a result of the alleged funds available to the insurance company. The maximum assess-plume. Although the results of litigation are inherently unpredictable, ment for the current policy period is $83 million. Based on the Dominion does not expect the ultimate outcome of the case to have a severity of the incident, the board of directors of Dominion's nuclear material adverse impact on its results of operations, cash flows or insurer has the discretion to lower or eliminate the maximum retro-financial position. spective premium assessment. Dominion has the financial responsi-Dominion has determined that it is associated with 20 former bility for any losses that exceed the limits or for which insurance manufactured gas plant sites. Studies conducted by other utilities proceeds are not available because they must first be used for at their former manufactured gas plants have indicated that their stabilization and decontamination.

sites contain coal tar and other potentially harmful materials. None Dominion purchases insurance from NEIL to cover the cost of of the 20 former sites with which Dominion is associated is under replacement power during the prolonged outage of a nuclear unit investigation by any state or federal environmental agency, and no due to direct physical damage of the unit. Under this program, investigation or action is currently anticipated. At this time, it is Dominion issubject to a retrospective premium assessment for any not known to what degree these sites may contain environmental policy year inwhich losses exceed funds available to NEIL. The contamination. Dominion is not able to estimate the cost, if any, current policy period's maximum assessment is $30 million.

that may be required for the possible remediation of these sites. Old Dominion Electric Cooperative, a part owner of North Anna Power Station, and Massachusetts Municipal WNholesale Electric Nuclear Operations Company and-Central Vermont Public Service Corporation, part NuclearDecommissioning-Minimum FinancialAssurance-The owners of Millstone's Unit 3, are responsible for their share of the NRC requires nuclear power plant owners to annually update minirium nuclear decommissioning obligation and insurance premiums on financial assurance amounts for the future decommissioning of its applicable units, including any retrospective premium assessments nuclear facilities. Dominion's 2004 NRC minimum financial assurance and any losses not covered by insurance.

amount, aggregated for the nuclear units, was $2.6 billion and has Spent Nuclear Fuel-Under provisions of the Nuclear Waste Policy been satisfied by a combination of guarantees and the funds being Act of 1982, Dominion has entered into contracts with the Department collected and deposited inthe trusts.

of Energy (DOE) for the disposal of spent nuclear fuel. The DOE failed Nuclearlnsurance-The Price-Anderson Act provides the public up to begin accepting the spent fuel on January 31, 1998, the date pro-to $10.8 billion of protection per nuclear incident via obligations '

vided by the Nuclear Waste Policy Act and by Dominion's contracts required of owners of nuclear power plants. The Price-Anderson Act with the DOE. InJanuary 2004, Dominion and certain of its direct and Amendment of 1988 allows for an inflationary provision adjustment indirect subsidiaries filed a lawsuit inthe United States Court of every five years. Dominion has purchased $300 million of coverage-Federal Claims against the DOE inconnection with its failure to from the commercial insurance pools with the remainder provided commence accepting spent nuclear fuel. Dominion will continue to through a mandatory industry risk-sharing program. The NRC safely manage its spent fuel until it isaccepted by the DOE.

exempted Millstone's Unit 1 on March 30,2004 from the Secondary Financial Retrospective Assessment, reducing Dominion's licensed Litigation reactors to six. Ii the event of a nuclear incident at any licensed Virginia Power and Dominion Telecom were defendants ina class nuclear reactor inthe United States, Dominion could be assessed up to action lawsuit whereby the plaintiffs claimed that Virginia Power

$100.6 million for each of its six licensed reactors not to exceed $10 and Dominion Telecom strung fiber-optic cable across their land, million per year per reactor. There is no limit to the number of along an electric transmission corridor without paying compensa-incidents for which this retrospective premium can be assessed. tion. The plaintiffs sought damages for trespass and 'unjust The Price-Anderson Act was first enacted in 1957 and has been enrichment," as well as punitive damages from the defendants. In renewed three times-in 1967. 1975 and 1998. The Price- April 2004, the parties entered into a settlement agreement that Anderson Act expired on August 31, 2002, but operating nuclear was subsequently approved by the court inJuly 2004. Under the reactors continue to be covered by the law. Congress is currently terms of the settlement, a fund of $20 million has been established holding hearings to reauthorize the legislation. by Virginia Power to pay claims of current and former landowners Dominion's current level of property insurance coverage ($2.55 as well as fees of lawyers for the class. Costs of notice to the billion for North Anna, $2.55 billion for Surry, and $2.75 billion for class and administration of claims will be borne separately by Millstone) exceeds the NRC's minimum requirement for nuclear Virginia Power. The settlement agreement resulted inan after-tax power plant licensees of $1.06 billion per reactor site and includes charge of $7million inthe first quarter of 2004.

coverage for premature decommissioning and functional total loss.

D 2004/ Page 83

Notes to Consolidated Financial Statements. Continued Enron Bankruptcy Surety Bonds and Letters of Credit During 2002, Dominion terminated all outstanding and open posi- Dominion had also purchased $77 million of surety bonds and tions with Enron. Dominion submitted a claim inthe Enron bank- authorized the issuance of standby letters of credit by financial ruptcy case for the value of such contracts, measured at the institutions of $1.7 billion. Dominion enters into these arrangements to effective dates of contract termination. During the first quarter of facilitate commercial transactions by its subsidiaries with third parties.

2004, the bankruptcy court approved a settlement of Dominion's Indemnifications claim in the proceeding, resulting in a $2million after-tax benefit.

As part of commercial contract negotiations inthe normal course of Guarantees, Surety Bonds and Letters of Credit business, Dominion may sometimes agree to make payments to Guarantees compensate or indemnify other parties for possible future unfavorable As of December 31, 2004, Dominion and its subsidiaries had financial consequences resulting from specified events. The specified issued $7.8 billion of guarantees. including: events may involve an adverse judgment ina lawsuit or the imposition

• $3.6 billion to support commodity transactions of subsidiaries; of additional taxes due to a change intax law or interpretation of the

• $1.7 billion for subsidiary debt reflected on the Consolidated tax law. Dominion isunable to develop an estimate of the maximum Balance Sheets; potential amount of future payments under these contracts because

• $898 million related to a subsidiary leasing obligation for a new events that would obligate Dominion have not yet occurred or, if any power generation project; such event has occurred, Dormnion has not been notified of its occur-

• $656 million associated with a subsidiary's commitment to rence. However, at December 31,2004, management believes future purchase three electric power generating facilities from USGen. payments, if any, that could ultimately become payable under these The guarantee expired when Dominion completed the contract provisions, would not have a material impact on its results of acquisition on January 1,2005; operations, cash flows or financial position.

• $509 million related to subsidiaries' nuclear decommissioning Stranded Costs obligations; In 1999, Virginia enacted the Virginia Restructuring Act that estab-

• $408 million for guarantees supporting other agreements of lished a detailed plan to restructure Virginia's electric utility industry.

subsidiaries; and Under the Virginia Restructuring Act, the generation portion of

• $31 million for guarantees supporting third parties and equity Dominion's Virginia jurisdictional operations isno longer subject to method investees.

cost-based regulation. The legislation's deregulation of generation The commodity transaction guarantees are put in place to was an event that required the discontinuance of SFAS No. 71 for allow Dominion's subsidiaries the flexibility to conduct business the Virginia jurisdictional portion of Dominion's generation oper-with counterparties without having to post substantial cash ations in1999. InApril 2004, the Governor of Virginia signed into law collateral. Inorder for Dominion to experience a liability for the amendments to the Virginia Restructuring Act and the Virginia fuel

$3.6 billion capacity of the guarantees, Dominion would have to factor statute. The amendments extend capped base rates by three fully utilize credit with every counterparty it has issued a guaran- and one-half years, to December 31, 201U. unless modified or termi-tee, which management believes would be highly unlikely to nated earlier under the Virginia Restructuring Act. Inaddition to occur. As of December 31, 2004, Dominion had entered into - extending capped rates, the amendments:

transactions with counterparties, whereby the net exposure

• Lock in Dominion's fuel factor provisionsuntil the earlier of July under the guarantees related to these transactions was $678 1,2007 or the termination of capped rates; million, which is included inthe $795 million net amount due to

• Provide for a one-time adjustment of Dominion's fuel factor, these counterparties reported on Dominion's Consolidated effective July 1,2007 through December 31, 2010 (unless capped Balance Sheet at December 31, 2004. rates are terminated earlier under the Virginia Restructuring Act),

There are no significant liabilities reflected on Dominion's with no adjustment for previously incurred over-recovery or Consolidated Balance Sheets for its subsidiaries' power generation under-recovery, thus eliminating deferred fuel accounting for the project leasing obligation, nuclear obligations or other miscella- Virginia jurisdiction; and neous obligations.

• End wires charges on the earlier of July 1,2007 or the While the majority of these guarantees do not hava a termi- termination of capped rates, consistent with the Virginia nation date, Dominion may choose at any time to limit the applic- Restructuring Act's original timetable.

ability of such guarantees to future transactions.

Wires charges, also known as competitive transition charges, are As of December 31, 2004, substantially all of the officers' borrow-permitted to be collected by utilities until July 1,2007, under the ings under executive stock loan programs, which were guaranteed by Virginia Restructuring Act. Dominion has agreed to forego the collec-Dominion, have been repaid. Because of restrictions on corporate tion of wires charges in2005, and as such Virginia customers will not loans or guarantees for executives under the Sarbanes-Oxley Act of pay a fee if they switch from Dominion to a different service provider.

2002, Dominion has ceased its program of third party loans to execu-Dominion believes capped electric retail rates and, where appli-tives for the purpose of acquiring company stock.

cable, wires charges provided under the Virginia Restructuring Act provide an opportunity to recover a portion of its potentially stranded D 2004/ Page 84

Notes to Consolidated Financial Statements, Continued costs, depending on market prices of electricity and other factors. 2004 and 2003, Dominion had margin deposit assets (reported inother Stranded costs are those generation-related costs incurred or current assets) of $179 million and $157 million, respectively, and commitments made by utilities under cost-based regulation that may margin deposit liabilities (reported inother current liabilities) of $28 not be reasonably expected to be recovered ina competitive market. million and $12 million, respectively.

Even inthe capped rate environment, Dominion remains exposed Dominion maintains a provision for credit losses based on to numerous risks, including, among others, exposure to potentially factors surrounding the credit risk of its customers, historical stranded costs, future environmental compliance requirements, trends and other information. Management believes, based on changes intax laws, inflation and increased capital costs. At Dominion's credit policies and its December 31, 2004 provision for December 31, 2004, Dominion's exposure to potentially stranded costs credit losses, that it is unlikely that a material adverse effect on its" included: long-term power purchase contracts that could ultimately be financial position, results of operations or cash flows would occur determined to be above market; generating plants that could possibly as a result of counterparty nonperformance.

become uneconomic inaderegulated environment; and unfunded As a diversified energy company, Dominion transacts with obligations for nuclear plant decommissioning and postretirement major companies inthe energy industry and with commercial and benefits not yet recognized inthe financial statements. residential energy consumers. These transactions principally occur inthe Northeast, Midwest and Mid-Atlantic regions of the United States; however, management does not believe that this geo-

23. Fair Value of Financial Instruments graphic concentration contributes significantly to Dominion's Substantially all of Dominion's financial instruments are recorded overall exposure to credit risk. Inaddition, as a result of its large at fair value, with the exception of the instruments described and diverse customer base, Dominion is not exposed to a sig-below that are reported at historical cost. Fair values have been nificant concentration of credit risk for receivables arising from determined using available market information and valuation utility electric and gas operations, including transmission services methodologies considered appropriate by management. The finan- and retail energy sales.

cial instruments' carrying amounts and fair values as of December Dominion's exposure to credit risk isconcentrated primarily within 31, 2004 and 2003 were as follows: its sales of gas and oil production and energy trading, marketing and commodity hedging activities, as Dominion transacts with a smaller,

- 2004 2003 less diverse group of counterparties and transactions may involve Estimated Estimated Carrying Fair Cartying Fair large notional volumes and potentially volatile commodity prices.

Amount ValueM" Amount Value', Energy trading, marketing and hedging activities include trading of (millions) energy-related commodities, marketing of merchant generation output, Long-term debt $15,446 $15,499 $15.588 $16,514 structured transactions and the use of financial contracts for Junior subordinated enterprise-wide hedging purposes. At December 31, 2004, gross credit notes payable to exposure related to these transactions totaled $1.27 billion, reflecting affiliated trusts 1,423 1,595 1,440 1,608 the unrealized gains for contracts carried at fair value plus any out-1I)Fairvalue isestimated using market pr ces. Where available, and interest rates standing receivables (net of payables, where netting agreements currently available for issuance of debt with similar terms and rem3ining maturities exist), prior to the application of collateral. After the application of The carrying amount of debt issues with short-term maturities and variable ratrs collateral, Dominion's credit exposure is.educed to $1.25 billion. Of refinanced at current market rates isa reasonable estimate of their fair value.

this amoun'. investment grade ccunterparties represent 85% and no single couriterparty exceeded 6%.

24. Credit Risk Credit risk isthe risk of financial loss to Dominion if counterparties fail 25. Equity Method Investments and Affiliated Transactions to perform their contractual obligations. Inorder to minimize overall At December 31, 2004 and 2003, Dominion's equity method invest-credit risk, Dominion maintains credit policies, including the evaluation ments totaled $387 million and $437 million, respectively, and of counterparty financial condition, collateral requirements and the use equity earnings on these investments totaled $34 million in2004, of standardized agreements that facilitate the netting of cash flows $25 million in2003 and $11 million in2002. Dominion received associated with a single counterparty. Inaddition, counterparties may dividends from these investments of $37 million, $28 million and make available collateral, including letters of credit or cash held as $36 million in2004, 2003 and 2002, respectively. Dominion's margin deposits, as a result of exceeding agreed-upon credit limits, or equity method investments are reported on the Consolidated may be required to prepay the transaction. Amounts reported as Balance Sheets inother investments, except for the international margin deposit liabilities represent funds held by Dominion that investments discussed below, which are classified as part of resulted from various trading counterpartics exceeding agreed-upon assets held for sale inother current assets. Equity earnings on credit limits established by Dominion. Amounts reported as margin these investments are reported on the Consolidated Statements of deposit assets represent funds held on deposit by various trading Income in other income (loss). See Note 26 for discussion of DCI's counterparties that resulted from Dominion exceeding agreed-upon equity method investments.

credit limits established by the counterparties. As of December 31, D 2004 /Page 85

Notes to Consolidated Financial Statements. Continued International Investments amount of $123 million, Dominion received $113 million cash and a CNGI was engaged in energy-related activities outside of the $7million 3%subordinated secured note in the new CDO structure United States, primarily through equity investments inAustralia and recorded an impairment charge of $3million. The equity inter-and Argentina. After completing the CNG acquisition, Dominion's ests inthe new COO structure, a voting interest entity, are held by an management committed to a plan to dispose of the entire CNGI entity that isnot affiliated with Dominion.

operation consistent with its strategy to focus on its core business. Simultaneous with the above transaction, the new CDO structure During 2003, Dominion recognized impairment losses totaling $84 acquired all of the loans held by two special purpose trusts that million ($69 million after-tax) related primarily to investments ina were established in2001 and 2000 to facilitate OCI's securitization pipeline business located inAustralia and a small generation facility in of certain loan receivables. DCI's original transfers of the loans to Kauai, Hawaii that was sold inDecember 2003 for cash proceeds of the CLO trusts qualified as sales under SFAS No. 125, Accounting for

$42 million. These impairment losses represented adjustments to the Transfers and Servicing of FinancialAssets and Extinguishments of assets' carrying amounts to reflect Dominion's then current evaluation Liabilities. Only after receiving consents from non-affiliated third of fair market value less estimated costs to sell, which were derived parties, the CLO trusts' goveming agreements were amended to from a combination of actual 2003 transactions, management esti- permit the sale of their financial assets into the new COO structure mates, and other fair market value indicators. in2003. Inconsideration for the sale of loans to the new COO struc-In2004, Dominion received cash proceeds of $52 million and ture, the trusts received $243 million of subordinated secured 3%

recognized a gain in other income of $9million from the sale of a notes inthe new COO structure and $119 million incash, which was portion of the Australian pipeline business inwhich CNGI held an used by the CLO trusts to redeem all of their outstanding senior debt investment. Dominion also recognized an $18 million benefit from securities. As of December 31, 2003, Dominion still held residual an adjustment to the carrying amount of this investment to reflect interests in the CLO trusts, the value of which depended solely on its then current estimate of fair value, less estimated costs to sell. the subordinated 3%notes issued by the new COO. Inconnection At Decembar 31, 2004, Dominion's remaining CNGI investment with a review of the remaining assets inthe CLO trusts, DCI is accounted for at fair value. Management expects this $4million recorded impairments totaling $23 million in2003. Dominion investment to be sold by the end of 2006. received its distribution of the new COO notes inthe first quarter of 2004 upon liquidation of the trusts.

26. Dominion Capital, Inc. There were no mortgage securitizatiors in2003 or 2004.

As of December 31, 2004, Dominion has substantially exited the Activity for the subordinated notes related to the new COO struc-core DCI financial services, commercial lending and residential ture, retained interests from securitizations of CMO's and the CLO mortgage lending businesses. and COO retained interests issummarized as follows:

Dominion is required by the SEC under the 1935 Act to divest of Retained all remaining DCI investment holdings by January 2006. Domin- CMO lnterests-CLO/CDO ion's Consolidated Balance Sheet reflects the following DCI assets Imilrions) as of December 31, 2004: Balance at January 1;Z03 $189 $ 281 Amortization 121 tmzieiosl Cash received 1101 (1I Current assets S 25 Retained securitization 7 Available for sale securities 335 Fair value adjustment 1361 1151 Other long-term investments 102 Balance at December 31, 2003 141 272 Property, plant and equipment net 15 Liquidation of retained interest in CLO Deferred charges and cther assets 121 trusts (2311 Total $599 Distributions of new COO notes to Dominion 235 Securitizations of Financial Assets Interest income 9 Amortization (1)

At December 31, 2004 and 2003, DCI held $335 million and $413 Cash received (27) 14) million, respectively, of retained interests from the securitization of Fairvalue adjustment 146) (13) financial assets, which are classified as available-for-sale secu- BalanceatDecember31,2004 $ 67 $268 rities. The retained interests resulted from prior year securitiza-tions of commercial loans receivable incollateralized loan Key Economic Assumptions and Sensitivity Analyses obligation (CLO), collateralized debt obligation (CDO) and Retained interests in CLOs and COOs are subject to credit loss and collateralized mortgage obligation (CMO) transactions. interest rate risk. Retained interests inCMOs are subject to credit Inconnection with Dominion's ongoing efforts to divest its loss, prepayment and interest rate risk. Given the declining remaining financial services investments, Dominion executed certain residual balances and the lower weighted-average lives due to the agreements in the fourth quarter of 2003 that resulted inthe sale of passage of time, adverse changes of up to 20% inassumed commercial finance receivables, a note receivable, an undivided prepayment speeds, credit losses and interest rates are estimated interest ina lease and equity investments to a new COO structure. In ineach case to have less than a $10 million pre-tax impact on exchange for the sale of these assets with an aggregate carrying future results of operations.

D 2004I/Page 86

Notes to Consolidated Financial Statements, Continued Impairment Losses Corporate and Other includes the operations of Dominion's The table below presents a summary of asset impairment losses corporate, service company and other operations (including associated with DCI operations. unallocated debt), DCI and the net impact of Dominion's dis-continued telecommunications operations that were sold in May Year Ended December 31 2004 2003 2002 2004. Inaddition, the contribution to net income by Dominion's (milions) primary operating segments isdetermined based upon a measure Retained interests from CMO 4 of profit that executive management believes represents the securitizatiinst $46 S 36 $11 Retained interests from CLO/CDO segments' core earnings. As a result, certain specific items securitizationsfl) 13 15 attributable to those segments are not included in profit measures 2003 CDO transactions - 23 evaluated by executive management in assessing the segment's Venture capital and other equity investmentsnt 26 16 performance or allocating resources among the segments. These Deferred tax assets(3) - 26 specific items are reported inthe Corporate and Other segment Goodwill impairment( - 18 13 and in 2004 include:

Total $85 $134 $24

• Losses related to the discontinuance of hedge accounting for certain oil hedges and subsequent changes in the fair value of It) As aresult of economic conditions and historically low interest rates and the resulting those hedges during the third quarter; and impact oncredit losses and prepayment speeds, Dominion recorded impairments ofits

• Charges reflecting Dominion's valuation of its interest ina retained interests from CMO.COO andCLOsecuritizations in 2004. 2003 and 2002.Dominion updated itscredit loss and prepayment assumptions to reflect its recent experience. long-term power tolling contract and the termination of certain 121 Other impairments were recorded primarily dueto asset dispositions. long-term power purchase agreements.

131 SeeNote 7 for discussion of deterred income taxes.

(41See Note 13 for discussion of goodwill impairments. Specific items in 2003 include:

• Cumulative effect of changes in accounting principles;

• Incremental restoration expenses associated with Hurricane

27. Operating Segments Isabel; Dominion is organized primarily on the basis of products and serv-

• Charges for the termination of certain long-term power ices sold inthe United States. Dominion manages its operations purchase agreements and restructuring of certain electric sales through the following segments: contracts: and Dominion Generation includes the generation operations of

• Severance costs for workforce reductions.

Dominion's electric utility and merchant fleet as well as coal and In 2002, there were no specific items attributable to Dominion's emissions trading and marketing activities.

primary operating segments reported inthe Corporate and Other Dominion Energyincludes Dominion's electric transmission, natural gas transmission pipeline and storage businesses, an LNG segment.

During the fourth quarter of 2004, Dominion performed an facility, certain natural gas production, as well as Clearinghouse evaluation of its Dominion Energy Clearinghouse trading and (energy trading and marketing and aggregation of gas supply).

marketing operations (Clearinghouse), which resulted in a decision Dominion Deliveryincludes Dominion's electric and gas dis-to exit certain energy trading activities and instead focus on the tribution systems and customer service operations, as well as optimization of company assets. Beginning in 2005, all revenues nonregulated retail energy marketing operations.

and expenses from the Clearinghouse's optimization of company Dominion Expioration & Production(E&P) includes Dominion's--

assets will be reported as part of the results of the business gas and oil exploration, development and production operations.

segments operating the related assets, inorder to better reflect Operations are located in several major producing basins in the the performance of the underlying assets. As a result of these lower 48 states, including the outer continental shelf and deep-changes, 2004 and 2003 results now reflect revenues and water areas of the Gulf of Mexico, and Western Canada.

expenses associated with Clearinghouse coal and emissions trading and marketing activities inthe Dominion Generation segment.

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

D 2004/ Page 87

Notes to Consolidated Financial Statements, Continued The following table presents segment information pertaining to Dominion's operations:

Dominion Dominion Dominion Dominion Corporate and Adjustments & Consolidated Generation Energy Delivery E&P Other Eliminations Total (millions) 2004 Total revenue from external customers $5,144 $2,047 $3,757 S2M272 $ 69 $ 683 - $13,972 Intersegment revenue 574 384 77 157 509 (1,701) -

Total operating revenue 5,718 2,431 3,834 2.429 578 (1,018) 13,972 Interest income 52 14 8 2 269 (244) 101 Interest and related charges 254 62 151 94 622 (244) 939 Depreciation, depletion and amortization 282 116 316 558 35 (2) 1,305 Equity inearnings of equity method investees 11 12 1 (1) 11 - 34 Income tax expense (benefit) 321 119 256 314 (310) - 700 Loss from discontinued operations, net of tax - - - - (15) - (15)

Net income (loss) 525 190 466 595 (527) - 1,249 Investment in equity method investees 162 94 5 40 86 - 387 Capital expenditures 623 354 441 1,311 21 - 2,750 Total assets (billions at December31) 14.5 7.2 9.2 11.3 14.3 (11.1) 45.4 2003 Total revenue from external customers $4,482 $1,863 $3,287 $1,841 $ 149 .$ 456 $12,078 Intersegment revenue 293 493 61 150 591 (1.588) -

Total operating revenue 4,775 2,356 3.348 1,991 740 (1,132) 12,078 Interest income 52 8 14 1 271 (237) 109 Interest and related charges 239 64 171 82 656 (237) 975 Depreciation, depletion and amortization 229 104 302 532 49 - 1,216 Equity inearningsofequitymethodinvestees 13 12 - 6 (6) - 25 Loss from discontinued operations, net of tax - - - - (642) - (642)

Income tax expense (benefit) 312 223 236 220 (394) - 597 Net income (loss) 512 346 453 415 (1,408) - 318 Investment in equity method investees 166 85 5 51 130 - 437 Capital expenditures 1,303 319 485 1,311 20 - 3,438 Total assets Ibillions at December 31) 15.0 7.3 9.0 9.2 14.3 (11.3) 43.5 2002 Total revenue from external customers $4,410 $1,008 $2,707 $1,629 $ 250 $ 214 $10,218 Intersegmentrevenue 51 386 23 90 568 (1.118) -

Total operating revenue 4,461 1,394 2,730 1,719 818 (904) 10,218 Interest income 28 2 10 - 308 (248) 100 Interest and related charges 234 56 171 88 644 (248) 945 Depreciation, depletion and amortization 295 98 302 592 60 - 1,258 Equity inearnings of equity method investees 19 10 - 5 (23) - 11 Income tax expense (benefit) 330 172 201 165 (187) - 681 Net income (loss) $ 561 $ 268 $ 422 $ 380 $ (269) - $ 1,362 As of December 31, 2004 and 2003, approximately 2% and 3%, respectively of Dominion's total long-lived assets were associated with international operations. For the years ended December 31, 2004, 2003 and 2002, approximately 2%, 2%and 1%, respectively, of operating revenues were associated with international operations.

D 2004/Page 88

Notes to Consolidated Financial Statements, Continued

28. Gas and Oil Producing Activities (unaudited)

Capitalized Costs The aggregate amounts of costs capitalized for gas and oil producing activities, and related aggregate amounts of accumulated depreciation.

depletion and amortization, at December 31, 2004 and 2003 follow:

2004 2003 (millions)

Capitalized costs of:

Proved properties $8,246 $7,561 Unproved properties 1,623 1,721 9,869 9,282 Accumulated depreciation of:

Proved properties 1,921 1,476 Unproved properties 109 126 2,030 1,602 Net capitalized costs $7,839 $7,680 Total Costs Incurred The following costs were incurred in gas and oil producing activities during the years ended December 31, 2004, 2003 and 2002:

2004 . 2003 2002 United United United Total States Canada Total States Canada Total States Canada Imillions)

Property acquisition costs:

Proved properties $ 20 $ 20 - $ 181 $ 181 - S 243 $ 243 Unproved properties 116 102 $ 14 133 125 $ 8 177 170 $7 136 122 14 314 306 8 420 413 7 Exploration costs 213 199 14 291 266 25 267 260 7 Development costs"' 915 841 74 667 604 63 760 679 81 Total $1264 $1,162 $102 S.272 $1,176 $96 $1,447 $1,352 $95 11lDevelopment costs incurred for proved undeveloped reserves were $172 million, $182 million and $223 million for 2004. 2003 and 2002, respectively.

Results of Operations Dominion cautions that the following standardized disclosures required by the FASB do not represent the results of operations based on its historical financial statements. Inaddition to requiring different determinations of revenue and costs, the disclosures exclude the impact of interest expense and corporate overhead.

2004 2003 2002 United United United Total States Canada Total States Canada Total States Canada (millionsl Revenue Inet of royalties) from:

Salestononaffiliatedcompanies $1,526 $1297 $229 $1,736 $1,552 $184 $1,396 $1,257 $139 Transfers to otheroperations 195 195 - 185 185 - 97 97 -

Total 1,721 1,492 229 1,921 1,737 184 1,493 1,354 139 Less:

Production Iliftingl costs 394 309 85 357 294 63 272 220 52 Depreciation, depletion and amortization 560 497 63 526 470 56 502 452 50 Income tax expense 295 266 29 356 350 6 222 209 13 Results of operations $ 472 $ 420 $ 52 S 682 S 623 $ 59 $ 497 $ 473 S 24 D 2004 / Page 89

Notes to Consolidated Financial Statements, Continued Company-Owned Reserves Estimated net quantities of proved gas and oil (including condensate) reserves inthe United States and Canada at December 31, 2004, 2003 and 2002, and changes inthe reserves during those years, are shown in the two schedules that follow:

2004 2003 2002 United United United Total States Canada Total States Canada Total States Canada (billion cubic feet)

Proved developed and undeveloped reserves-Gas At January 1 5,369 4,801 568 5,098 4,458 640 4,090 3,517 573 Changes in reserves:

Extensions, discoveries and other additions 400 342 58 821 767 54 874 769 105 Revisionsofpreviousestimates'" (28) 163 (191) (147) (71) (76) 158 145 13 Production (371) (327) (44) (396) (346) (50) (399) (346) (53)

Purchases of gas in place 10 10 - 133 133 - 381 379 2 Sales of gas in place (377) (85) (292) (140) (140) - (6) (6) -

At December 31 5,003 4,904 99 5,369 4,801 568 5,098 4,458 640 Proved developed reserves-Gas At January 1 4.006 3,553 453 4,035 3,549 486 3,466 3,026 440 At December 31 3,776 3,680 96 4,006 3,553 453 4,035 3,549 486 Proved developed and undeveloped reserves-Oil (thousands of barrels)

At January 1 169,934 135,914 34,020 169,230 138,798 30,432 140,567 115,988 24,579 Changes in reserves:

Extensions, discoveries and other additions 9,386 7,546 1,840 13,223 7,818 5.435 24,326 24,273 53 Revisions of previous estimates(2t (17,911) (5,584) (12327) 697 1,433 (736) 11,165 4,293 6,872 Production (10,001) (8,800) (1,201) (8,723) (7.6421 (1,081) (9,725) (8,653) (1,072)

Purchases of oil in place 666 666 - 380 380 - 2,928 2,928 -

Sales of oil inplace (3,476) (818) (Z658) (4,8731 (4,873) - (31) (31) -

AtDecember31 148,598 128,924 19,674 169.934 135,914 34,020 169,230 138,798 30,432 Proved developed reserves-Oil At January 1 59,754 42,347 17,407 65,823 47.759 18,064 63,777 46,473 17,304 AtDecember31 98,841 87,382 11,459 59,754 42,347 17,407 65,823 47,759 18,064 (11Approximately 187 Bcf of the Canadian reserve revisions pertained to properties sold in2004 and resulted from performance-based reserve reclassifications from proved undeveloped to unproved.

12)Approximately 8.3 million barrels of the Canadian reserve revisions pertained to properties sold in2004 and resulted from performance-based reserve re-determinations on two British Columbia enhanced oil recovery projects.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein The following tabulation has been prepared in accordance with the FASB's rules for disclosure of a standardized measure of discounted future net cash flows relating to proved gas and oil reserve quantities owned by Dominion:

2004 2003 2002 United United United Total States Canada Total States Canada Total States Canada Imillions)

Future cash inflows") $36,819 $35,735 $1,084 $36,486 $32,922 $3,564 $28,337 $25,344 $2,993 Less:

Future development costs(2 1 1,527 1,488 39 1,505 1,391 114 1,092 1,005 87 Future production costs 5,609 5,302 307 5,582 4,765 817 3,603 2,979 624 Future income tax expense 10.152 9,909 243 9,457 8,715 742 7,582 6,904 678 Future cash flows 19,531 19,036 495 19,942 18,051 1,891 16,060 14,456 1,604 Less annual discount (10% a year) 10,505 10,275 230 10,709 9,745 964 8,255 7,436 819 Standardized measure of discounted future net cash flows $ 9,026 $ 8,761 $ 265 $ 9,233 $ 8,306 $ 927 $ 7,805 $ 7,020 $ 785 (1)Amounts exclude the effect of derivative instruments designated as hedges of future sales of production at year-end.

(2)Estimated future development costs, excluding abandonment. for proved undeveloped reserves are estimated lo be $451 million, $223 million and $236 million for 2005, 2006 and 2007. respectively.

D 20041 Page 90

Notes to Consolidated Financial Statements, Continued Inthe foregoing determination of future cash inflows, sales prices for gas and oil were based on contractual arrangements or market prices at year-end. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year end, assuming the continuation of existing economic conditions. Future income taxes were computed by applying the appropriate year-end or future statutory tax rate to future pretax net cash flows, less the tax basis of the proper-ties involved, and giving effect to tax deductions, permanent differences and tax credits.

It is not intended that the FASB's standardized measure of discounted future net cash flows represent the fair market value of Dominion's proved reserves. Dominion cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate isarbitrary. Inaddition, costs and prices as of the measurement date are used inthe determinations, and no value may be assigned to probable or possible reserves.

The following tabulation isa summary of changes between the total standardized measure of discounted future net cash flows at the beginning and end of each year:

2004 2003 2002 (millions)

Standardized measure of discounted future net cash flows atJanuary 1 S9.233 $ 7,805 $ 3,213 Changes inthe year resulting from:

Sales and transfers of gas and oil produced during the year, less production costs (2,004) (1,997) (1,086)

Prices and production and development costs related to future production 1,656 480 3,975 Extensions, discoveries and other additions. less production and development costs 1,118 1,920 2,039 Previously estimated development costs incurred during the year 172 182 223 Revisions of previous quantity estimates (734) (918) (152)

Accretion of discount 1,359 1,149 426 Income taxes (291) (679) (2,639)

Other purchases and sales of proved reserves inplace (878) 84 799 Other (principally timing of production) (605) 1,207 1,007 Standardized measure of discounted future net cash flows at December 31 S 9,026 $ 9,233 $ 7,805 D 2004/ Page 91

Notes to Consolidated Financial Statements. Continued

29. Quarterly Financial and Common Stock Data (unaudited) sary inthe opinion of management for a fair statement of the results for the interim periods. Results for interim periods may A summary of the quarterly results of operations for the years fluctuate as a result of weather conditions, changes inrates and ended December 31, 2004 and 2003 follows. Amounts reflect all other factors.

adjustments, consisting of only normal recurring accruals, neces-First Second Third Fourth Quarter Quarter Quarter Quarter Full Year (mil lions, except per share amounts) 2004 Operating revenue $ 3,879 $ 3,040 $ 3,292 $ 3.761 $13,972 Income from operations 890 580 744 503 2,717 Income from continuing operations before cumulative effect of changes in accounting principles 445 258 337 224 1,264 Net income 437 251 337 224 1,249 Basic EPS:

Income from continuing operations before cumulative effect of changes in accounting principles 1.37 0.79 1.02 0.67 3.84 Net income 1.35 0.76 1.02 0.67 3.80 Diluted EPS:

Income from continuing operations before cumulative effect of changes in accounting principles 1.36 0.79 1.02 0.67 3.82 Net income 1.34 0.76 1.02 0.67 3.78 Dividends paid per share 0.645 0.645 0.645 0.665 2.60 Common stock prices (high-low) 65.85- 64.75- 65.87- 68.85- 68.85-S61.20 $ 60.78 S 6Z07 $ 62.97 $ 60.78 2003 Operating revenue $ 3,579 $ 2,630 $ 2,853 $ 3,016 $12,078 Income from operations 1,014 577 698 272 2,561 Income (loss) from continuing operations before cumulative effect of changes in accounting principles 409 246 326 132) 949 Net income (loss) 508 240 (2561 (174) 318 Basic EPS:

Income (loss) from continuing operations before cumulative effect of changes inaccounting principles 1.33 0.78 1.01 (0.10) 2.99 Net income (loss) 1.64 0.76 (0.791 (0.54) 1.00 Diluted EPS:

Income (loss) from continuing operations before cumulative effect of changes inaccounting principles 1.32 0.78 1.01 (0.10) 2.98 Net income (loss) 1.64 0.76 (0.79) (0.54) 1.00 Dividends paid per share 0.645 0.645 0.645 0.645 2.58 Common stock prices (high-low) 58.62- 65.95- 64.28- 64.45- 65.95-

$ 51.74 $ 54.75 $ 58.05 $ 59.27 $ 51.74 Dominion's 2004 results include the impact of the following

• Fourth quarter results include a $112 million after-tax charge significant items: reflecting Dominion's valuation of its interest ina long-term

• Third quarter results include $61 million of after-tax losses power tolling contract that is subject to a planned divestiture in related to the discontinuance of hedge accounting for certain the first quarter of 2005 and a $61 million after-tax benefit due oil hedges, resulting from an interruption of oil production in to the recognition of business interruption insurance revenue the Gulf of Mexico caused by Hurricane Ivan, and subsequent associated with the recovery of delayed gas and oil production changes inthe fair value of those hedges: and due to Hurricane Ivan.

D 2004/ Page 92

Dominion's 2003 results include the impact of the following Item 9.Changes in and Disagreements significant items: with Accountants on Accounting and

• First quarter results include a $113 million after-tax gain representing the cumulative effect of adopting SFAS No. 143 Financial Disclosure and EITF 02-3 described in Note 3 and $63 million of losses None.

related to Dominions discontinued telecommunications operations described in Note 9.

• Third quarter results include $80 million of after-tax Item 9A. Controls and Procedures incremental restoration expenses associated with Hurricane Senior management, including the Chief Executive Officer and Isabel and $582 million of losses related to Dominion's Chief Financial Officer, evaluated the effectiveness of Dominion's discontinued telecommunications operations described in disclosure controls and procedures as of the end of the period Note 9; and covered by this report. Based on this evaluation process, the Chief

• Fourth quarter results include $42 million of after-tax Executive Officer and Chief Financial Officer have concluded that incremental restoration expenses associated with Hurricane Dominion's disclosure controls and procedures are effective. There Isabel, $100 million of losses related to Dominion's were no changes in Dominion's internal control over financial discontinued telecommunications operations described inNote reporting that occurred during the last fiscal quarter that have 9 and a $102 million after-tax loss representing the cumulative materially affected, or are reasonably likely to materially affect, effect of adopting Issue C20 and FIN 46R described in Note 3. Dominion's internal control over financial reporting.

See Item B.Financial Statements and Supplementary Data for Management's Annual Report On Internal Control Over Financial Reporting and the Independent Registered Public Accounting Firm's report with respect to management's assessment of the effectiveness of internal control over financial reporting.

Item 9B. Other Information On February 25, 2005, Thomas F.Farrell, II,was elected to Domin-ion's Board of Directors, effective March 1,2005. Mr. Farrell is also President and Chief Operating Officer of Dominion and during 2004 received an annual salary and other compensation for such service as reported under Executive Compensation in Dominion's 2005 Proxy Statement, File No. 1-8489. At this time, Mr. Farrell has not been appointed to serve on any Board committees.

D 2004/ Page 93

Part III Item 10. Directors and Executive Officers The information regarding equity securities of Dominion that of the Registrant are authorized for issuance under its equity compensation plans contained under the heading Executive Compensation-Equity The following information is incorporated by reference from the Compensation Plans in the 2005 Proxy Statement is incorporated 2005 Proxy Statement, File No. 1-8489, which will be filed on or by reference.

around March 18, 2005 (the 2005 Proxy Statement):

• Information regarding the directors required by this item is found under the heading Election of Directors.

• Information regarding Dominion's Audit Committee required by Item 13. Certain Relationships and Related this item is found under the heading The Board. Transactions

• Information regarding Dominion's Code of Ethics required by The information concerning certain transactions with executive this item is found under the heading Govemance. officers under the heading Executive Compensation-Executive The information concerning the executive officers of Dominion Stock Purchase Programs and other transactions contained under required by this item is included inPart I of this Form 10-K under the heading Certain Relationships in the 2005 Proxy Statement is the caption Executive Officers of the Registrant. incorporated by reference.

Item 11. Executive Compensation Item 14. Principal Accountant Fees and The information regarding executive compensation contained under Services the headings Committee Report on Executive Compensation and The information concerning principal accounting fees and services Executive Compensation and the information regarding director contained under the heading Auditors in the 2005 Proxy Statement compensation contained under the heading The Board inthe 2005 is incorporated by reference.

Proxy Statement is incorporated by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management The information concerning stock ownership by directors, executive officers and five percent beneficial owners contained under the heading Share Ownership inthe 2005 Prcxy Statement is incorporated by reference.

D 20041 Psge 94

Part IV Item 15. Exhibits and Financial Statement Schedules (a)Certain documents are filed as part of this Form 10-K and are incorporated by reference and found on the pages noted.

1.Financial Statements See Index on page 47.

2. Financial Statement Schedules Page Report of Independent Registered Public Accounting Firm 100 Schedule I-Condensed Financial Information of Registrant 101 All other schedules are omitted because they are not applicable, or the required information is either not material or is shown inthe financial statements or the related notes.

3.Exhibits 3.1 Articles of Incorporation as ineffect August 9. 1999, as amended effective March 12, 2001 (Exhibit 3.1, Form 10-K for the year ended December 31, 2002, File No. 1-8489, incorporated by reference).

3.2 Bylaws as ineffect on October 20, 2000 (Exhibit 3, Form 10-0 for the quarter ended September 30, 2000, File No. 1-8489, incorporated by reference).

4.1 See Exhibit 3.1 above.

4.2 Indenture of Mortgage of Virginia Electric and Power Company, dated November 1,1935, as supplemented and modified by fifty-eight Supplemental Indentures (Exhibit4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255, incorporated by reference); Sixty-Seventh Supplemental Indenture (Exhibit 4(i), Form 8-K, dated April 2, 1991, File No.1-2255, incorporated by reference); Seventieth Supplemental Indenture, (Exhibit 4(iii), Form 8-K, dated February 25, 1992, File No. 1-2255, incorporated by reference); Seventy-First Supplemental Indenture (Exhibit 4(i)) and Seventy-Second Supplemental Indenture, (Exhibit 4(ii), Form 8-K, dated July 7, 1992, File No. 1-2255, incorporated by reference); Seventy-Third Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated August 6, 1992, File No. 1-2255, incorporated by reference); Seventy-Fourth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated February 10,1993, File No.1-2255, incorporated by reference); Seventy-Fifth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated April 6,1993, File No. 1-2255, incorporated by reference); Seventy-Sixth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated April 21,1993, File No. 1-2255, incorporated by reference); Seventy-Seventh Supplemental Indenture, (Exhibit 4(i),

Form 8-K, dated June 8, 1993, File No. 1-2255, incorporated by reference); Seventy-Eighth Supplemental Indenture, (Exhibit 4(i),

Form 8-K, dated August 10, 1993, File No. 1-2255, incorporated by reference); Seventy-Ninth Supplemental Indenture, (Exhibit 4(i),

Form 8-K, dated August 10, 1993, File No. 1-2255, incorporated by reference); Eightieth Supplemental Indenture, (Exhibit 4(i),

Form 8-K, dated October 12, 1993, File No.1-2255, incorporated by reference); Eighty-First Supplemental Indenture, (Exhibit 4(iii).

Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference); Eighty-Second Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated January 18, 1994, File No. 1-2255, incorporated by reference); Eighty-Third Supplemental Indenture (Exhibit 4(i), Form 8-K, dated October 19,1994, File No. 1-2255, incorporated by reference); Eighty-Fourth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated March 23, 1995, File No. 1-2255, incorporated by reference); and Eighty-Fifth Supple-mental Indenture (Exhibit 4(i), Form 8-K, dated February 20, 1997, File No. 1-2255, incorporated by reference).

4.3 Indenture, dated as of June 1,1986, between Virginia Electric and Power Company and JP Morgan Chase Bank (formerlyThe Chase Manhattan Bank and Chemical Bank) (Exhibit 4(v), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference).

4.4 Indenture, dated April 1,1988, between Virginia Electric and Power Company and JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Chemical Bank), as supplemented and modified by a First Supplemental Indenture, dated August 1,1989, (Exhibit 4(vi), Form 10-K for the fiscal year ended December 31, 1993, File No.1-2255, incorporated by reference); Second Supplemental Indenture, dated May 1, 1999 (Exhibit 4.2, Form S-3, File No. 333-7615, as filed on April 13, 1999, incorporated by reference).

4.5 Subordinated Note Indenture, dated as of August 1, 1995 between Virginia Electric and Power Company and JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Chemical Bank), as Trustee (Exhibit 4(a), Form S-3 Registration Statement File No.

333-20561 as filed on January 28, 1997, incorporated by reference), Form of Second Supplemental Indenture (Exhibit 4.6, Form 8-K filed August 20, 2002, No. 1-2255, incorporated by reference).

4.6 Form of Senior Indenture, dated as of June 1,1998, between Virginia Electric and Power Company and JP Morgan Chase Bank (formerly The Chase Manhattan Bank) as supplemented by the First Supplemental Indenture (Exhibit 4.2, Form 8-K, dated June 12, 1998, File No. 1-2255, incorporated by reference); Second Supplemental Indenture (Exhibit 4.2, Form 8-K, dated June 3, 1999, File No.1 -2255, incorporated by reference); Third Supplemental Indenture (Exhibit 4.2, Form 8-K, dated October 27, 1999, D 20041 Page 95

File No. 1-2255, incorporated by reference); Form of Fourth Supplemental Indenture (Exhibit 4.2, Form 8-K, dated March 22, 2001, File No. 1-2255, incorporated by reference); and Form of Fifth Supplemental Indenture (Exhibit 4.3, Form 8-K, dated March 22, 2001, File No. 1-2255, incorporated by reference); Form of Sixth Supplemental Indenture (Exhibit 4.2, Form 8-K, dated Jan-uary 24, 2002, incorporated by reference); Seventh Supplemental Indenture dated September 1,2002 (Exhibit 4.4, Form 8-K filed September 11, 2002, File No. 1-2255, incorporated by reference); Form of Ninth Supplemental Indenture (Exhibit 4.2, Form 8-K filed December 4,2003, File No. 1-2255, incorporated by reference); Form of Eighth Supplemental Indenture (Exhibit 4.2, Form 8-K filed February 27, 2003, File No. 1-2255, 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).

4.7 Indenture, Junior Subordinated Debentures, dated December 1, 1997, between Dominion Resources, Inc. and JP Morgan Chase Bank (formerly The Chase Manhattan Bank) as supplemented by a First Supplemental Indenture, dated December 1,1997 (Exhibit 4.1 and Exhibit 4.2 to Form S-4 Registration Statement, File No. 333-50653, as filed on April 21, 1998, incorporated by reference); Second and Third Supplemental Indentures, dated January 1,2001 (Exhibits 4.6 and 4.13, Form 8-K, dated January 9, 2001, incorporated by reference).

4.8 Indenture, dated as of May 1,1971, between Consolidated Natural Gas Company and JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Manufacturers Hanover Trust Company) (Exhibit (5)to Certificate of Notification at Commission File No. 70-5012, incorporated by reference); Fifteenth Supplemental Indenture dated as of October 1, 1989 (Exhibit (5)to Certificate of Notification at Commission File No. 70-7651, incorporated by reference); Seventeenth Supplemental Indenture dated as of August 1, 1993 (Exhibit (4)to Certificate of Notification at Commission File No. 70-8167, incorporated by reference); Eighteenth Supplemental Indenture dated as of December 1, 1993 (Exhibit (4)to Certificate of Notification at Commission File No. 70-8167, incorporated by reference); Nineteenth Supplemental Indenture dated as of January 28, 2000 (Exhibit (4A1(iii), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference); Twentieth Supplemental Indenture dated as of March 19, 2001 (Exhibit 4.1, Form 10-0 for the quarter ended September 30, 2003, File No. 1-3196, incorporated by reference)-

4.9 Indenture, dated as of April 1,1995, between Consolidated Natural Gas Company and The Bank of New York (as successor trustee to United States Trust Company of New York) (Exhibit (4)to Certificate of Notification at Commission File No. 70-8107);

First Supplemental Indenture dated January 28, 2000 (Exhibit (4A)(ii), Form 10-K for the fiscal year ended December 31, 1999, File No.1-3196, incorporated by reference); Securities Resolution No.1 effective as of April 12, 1995 (Exhibit 2 to Form 8-A filed April 21, 1995 under File No. 1-3196 and relating to the 7Y8% Debentures Due April 1.2005); Securities Resolution No. 2 effec-tive as of October 16, 1996 (Exhibit 2 to Form 8-A filed October 18, 1996 under file No. 1-3196'and relating to the 67/8%

Debentures Due October 15, 2006); Securities Resolution No. 3 effective as of December 10, 1996 (Exhibit 2 to Form 8-A filed December 12, 1996 under file No. 1-3196 and relating to the 65'a% Debentures Due December 1,2008); Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2 to Form 8-A filed December 12,1997 under file No. 1-3196 and relating to the 6.80% Debentures Due December 15, 2027); Securities Resolution No. 5 effective as of October 20, 1998 (Exhibit 2 to Form 8-A filed October 22, 1998 under file No. 1-3196 and relating to the 6%Debentures Due October 15, 201 0); Securities Resolution No. 6 effective as of September 21, 1999 (Exhibit 4A(iv), Form 10-K for the fiscal year ended December 31, 1999, File No.1 -

3196, and relating to the 71/4% Notes Due October 1,2004; incorporated by reference).

4.10 Form of Senior Indenture, dated June 1,2000, between Dominion Resources, Inc. and JP Morgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee (Exhibit 4 (iii), Form S-3; Registration Statemert, File No. 333-93187, incorporated by reference); First Supp!emental Indenture, dated June 1,2000 (Exhibit 4.2, Form 8-K, dated June 21, 2000, File No. 1-8489, incorporated by reference): Second Supplemental Indenture, dated July 1,2000 (Exhibit 4.2. Form 8-K, dated July 11, 2000, File No. 1-8489, incorporated by reference); Third Supplemental Indenture, dated July 1,2000 (Exhibit 4.3, Form 8,K dated July 11, 2000, incorporated by reference); Fourth Supplemental Indenture and Fifth Supplemental Indenture dated September 1,2000 (Exhibit 4.2, Form 8-K, dated September 8,2000, incorporated by reference); Sixth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.3, Form 8-K, dated September 8, 2000, incorporated by reference); Seventh Supplemental Indenture, dated October 1.2000 (Exhibit 4.2, Form 8-K, dated October 11, 2000, incorporated by reference); Eighth Supplemental Indenture, dated January 1,2001 (Exhibit 4.2, Form 8-K; dated January 23, 2001, incorporated by reference); Ninth Supplemental Indenture, dated May 1,2001 (Exhibit 4.4, Form 8-K. dated May 25, 2001, incorporated by reference); Form of Tenth Supplemental Indenture (Exhibit 4.2, Form 8-K filed March 18. 2002, File No. 1-8489, incorporated by reference); Form of Eleventh Supple-mental Indenture (Exhibit 4.2, Form 8-K filed June 25, 2002, File No. 1-8489, incorporated by reference.); Form of Twelfth Supplemental Indenture (Exhibit 4.2, Form 8-K filed September 11, 2002, File No. 1-8489, incorporated by reference); Thirteenth Supplemental Indenture dated September 16, 2002 (Exhibit 4.1, Form 8-K filed September 17, 2002, File No. 1-8489, incorporated by reference); Fourteenth Supplemental Indenture, dated August 20, 2003 (Exhibit 4.4, Form 8-K filed August 20, 2003, File No. 1-8489, incorporated by reference); Forms of Fifteenth and Sixteenth Supplemental Indentures (Exhibits 4.2 and 4.3 to Form 8-K filed December 12, 2002, File No. 1-8489, incorporated by reference); Forms of Seventeenth and Eighteenth Supplemental Indentures (Exhibits 4.2. and 4.3 to Form 8-K filed February 11, 2003, File No. 1-8489, incorporated by reference);

D 20041 Page 96

Forms of Twentieth and Twenty-first Supplemental Indentures (Exhibits 4.2 and 4.3 to Form 8-K filed March 4, 2003, File No.

1-8489, incorporated by reference); Form of Twenty-second Supplemental Indenture (Exhibit 4.2 to Form 8-K filed July 22, 2003, File No. 1-8489 incorporated by reference); Form of Twenty-Third Supplemental Indenture (Exhibit 4.2, Form 8-K filed December 9,2003, Fie No. 1-8489, incorporated by reference); Form of Twenty-Fifth Supplemental Indenture (Exhibit 4.2, Form 8-K filed January 14, 2004, File No. 1-8489, incorporated by reference); Form of Twenty-Sixth Supplemental Indenture (Exhibit 4.3, Form 8-K filed January 14, 2004, File No. 1-8489, incorporated by reference).

4.11 Indenture, dated April 1,2001, between Consolidated Natural Gas Company and Bank One Trust Company, National Association (Exhibit 4.1, Form S-3 File No. 333-52602, as filed on December 22,2000, incorporated by reference), as supplemented by the Form of First Supplemental Indenture, dated April 1,2001 (Exhibit 4.2, Form 8-K, File dated April 12, 2001, File No. 1'3196 incorporated by reference); Second Supplemental Indenture, dated October 25, 2001 (Exhibit 4.1, Form 8-K, dated October 23, 2001, File No. 1-3196, incorporated by reference); Third Supplemental Indenture, dated October 25, 2001 (Exhibit 4.3, Form 8-K, dated October 23, 2001, File No. 1-3196, incorporated by reference); Fourth Supplemental Indenture, dated May 1,2002 (Exhibit 4.4, Form 8-K, dated May 22, 2002, Form 1-3196, incorporated by reference); Form of Fifth Supplemental Indenture (Exhibit 4.2, Form 8-K filed November 25, 2003, File No. 1-3196, incorporated by reference); Form of Sixth Supplemental Indenture (Exhibit 4.2, Form 8-K filed November 16, 2004, File No. 1-3196, incorporated by reference).

4.12 Form of Indenture for Junior Subordinated Debentures, dated October 1,2001, between Consolidated Natural Gas Company and Bank One Trust Company, National Association (Exhibit 4.2, Form S-3 Registration No. 333-52602, as filed on December 22, 2000, incorporated by reference); as supplemented by the First Supplemental Indenture, dated October 23, 2001 (Exhibit 4.7, Form 8-K, dated October 16, 2001, File No. 1-3196, incorporated by reference).

4.13 Indenture, dated as of June 15, 1994, between Louis Dreyfus Natural Gas Corp., Dominion Oklahoma Texas Exploration and Production, Inc. and The Bank of NewYork (as successor trustee to Bank of Montreal Trust Company) (Exhibit 4.13, Form 10-K for the fiscal year ended December 31, 2001, File No. 1-8489, incorporated by reference); as supplemented by the First Supple-mental Indenture, dated as of November 1,2001 'Exhibit 4.7, Form 10-0 for the quarter ended September 30, 2001, incorporated by reference).

4.14 Indenture, dated as of December 11, 1997, between Louis Dreyfus Natural Gas Corp., Dominion Oklahoma Texas Exploration &

Production, Inc., and La Salle Bank National Association {formerly LaSalle National Bank) (Exhibit 4.14, Form 10-K for the fiscal year ended December 31, 2901, File No. 1-8489, incorporated by reference); as supplemented by the First Supplemental Indenture, dated as of November 1,2001 (Exhibit 4.9, Form 10-0 for the quarter ended September 30, 2001, incorporated by reference).

4.15 Dominion Resources, Inc. agrees to furnish to the Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of Dominion Resources, Inc.'s total consolidated assets.

10.1 Amended and Restated Interconnection and Operating Agreement, dated as of July 29, 1997 between Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit 10(v), Form 10-K for the fiscal year ended December 31, 1997, File No. 1-8489, incorporated by reference).

10.2 DRI Services Agreement, dated January 28, 2000, by and ' etween Dominion Resources, Inc., Dominion Resources Services, Inc.

and Consolidated Natural Gas Service Company, !nc. (Exhibit 1U(viii), Fornm10-K for the fiscal year ended December 31, 1999, File No. 1-8489, incorporated by reference). .

10.2 Services Agreement between Dominion Resourcas Services, Inc. and Virginia Electric and Power Company dated January 1, 2000 (Exhibit 10.19, Form 10-K far the fiscal year ended December 31, 1999, File No.1-2255, incorporated by reference).

10.3 PJM South Implementation Agreement between Virginia Electric and Fower Company and PJM Interconnection, L.L.C., dated September 30, 2002, as amended December 6,2002 (Exhibii 10.4, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).

10.4 $1,500,000,000 Three Year Credit Agreement among Dominion Resources, Inc., Virginia Electric and Power Company, Con-solidated Natural Gas Company and JPMorgan Chase Bank, as Administrative Agent for the Lenders, dated May 27, 2004 (Exhibit 10.3, Form 10-0 for the quarter ended March 31, 2004, File No. 1-8489, incorporated by reference).

10.5 $1,500,000,000 Three-Year Credit Agreement among Consolidated Natural Gas Company and Barclays Bank, as Administrative Agent for the Lenders, dated August 10, 2004 (Exhibit 10.1, Form 10-0 for the quarter ended September 30, 2004, File No.

1-8489, incorporated by reference).

10.6 $750,000,000 Three-Year Credit Agreement among Dominion Resources, Inc., Virginia Electric and Power Company, Con-solidated Natural Gas Company and JPMorgan Chase Bank, as Administrative Agent for the Lenders, dated as of May 30, 2002 (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2003, File No. 1-8489, incorporated by reference).

D 2004/ Page 97

10.7 Form of Settlement Agreement in the form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West Virginia and Dominion (Exhibit 10, Form 10-0 for the quarter ended March 31, 2003, File No. 1-8489, incorporated by reference).

10.8* 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).

10.9*, Dominion Resources, Inc.'s Cash Incentive Plan as adopted December20, 1991 (Exhibit 10(xxii), Form 10-K for the fiscal year ended December 31, 1991, File No. 1-8489, incorporated by reference).

10.10* Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, 1997, as amended and restated effective July 20, 2001 (Exhibit 10.1, Form 10-0 for the quarter ended June 30, 2001, File No. 1-8489, incorporated by reference).

10.11* Dominion Resources, Inc. Executive Stock Purchase and Loan Plan 11,dated February 15, 2000 (Exhibit 10.10, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).

10.12* Form of Employment Continuity Agreement for certain officers of Dominion, amended and restated July 15, 2003 2001 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2003, File No.1-8489, incorporated by reference).

10.13* 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).

10.14* 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).

10.1 5* 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).

10.16* 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).

10.17* 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).

10.18* 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).

10.19* Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, amended as of February 27, 2004 (Exhibit 10.15, Form 10-K for the fiscal year ended December 31, 2003, incorporated by reference); amended effective December 31, 2004 (Exhibit 10.1, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).

10.20* Dominion Resources, Inc. Directors Stock Compensation Plan, as amended February27, 2004 (Exhibit 10.16, Form 10-K for the fiscal year ended December 31, 2003, incorporated by reference); amended effective December 31, 2004 (Exhibit 10.2. Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).

10.21* Dominion Resources, Inc. Directors' Deferred Cash Compensation Plan, as amended and in effect September 20, 2002 (Exhibit 10.4, Form 10-0 for the quarter ended September 30, 2002, incorporated by reference); amended effective December 31, 2004 (Exhibit 10.3. Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).

10.22* Dominion Resources, Inc. Non-Employee Directors' Compensation Plan, effective January 1,2005 (Exhibit 10.4, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).

10.23* 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. 1-8489, incorporated by reference).

10.24* 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).

10.25* Dominion Resources, Inc. Stock Purchase Tool Kit Restricted Stock Exchange Form of Restricted Stock Award Agreement (Exhibit 10.12, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).

10.26* 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).

10.27* Arrangement with Thos. E.Capps regarding additional credited years of service for retirement and retirement life insurance purposes (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).

10.28* Employment Agreement dated September 30, 2002 between Dominion and Thos. E.Capps (Exhibit 10.1, Form 10-0 for the quarter ended September 30, 2002, File No. 1-8489, incorporated by reference) including supplemental letter, dated February 27, 2003 (Exhibit 10.22, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).

10.29* Form of Reimbursement Agreement between certain executive officers and Dominion (Exhibit 10(xxvii), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-2255, incorporated by reference).

D 20041 Pase 98

10.30* Letter agreement 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).

10.31

• Letter agreement between Doriinion and Thomas N.Chewning (Exhibit 10.25, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).

10.32* Offer of employment dated March 16, 2001 between Dominion and Duane C.Radtke (Exhibit 10.26, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).

10.33* Supplemental Retirement Agreement. dated October 15, 2004 between Dominion and Duane C.Radtke (Exhibit 10, Form 8-K filed October 19, 2004, File No. 1-8489, incorporated by reference).

10.34* 8ase salaries for named executive officers (filed herewith).

10.35* Non-employee directors' annual compensation (filed herewith).

12 Ratio of earnings to fixed charges (filed herewith).

21 Subsidiaries of the Registrant (filed herewith).

23.1 Consent of Deloitte & Touche LLP (filed herewith).

23.2 Consent of Ralph E.Davis Associates, Inc. (filed herewith).

23.3 Consent of Ryder Scott Company. L.P. (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 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 Officer 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.

D 20041 Page 99

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Shareholders and Board of Directors of Dominion Resources, Inc.

Richmond, Virginia We have audited the consolidated financial statements of Dominion Resources, Inc. and subsidiaries (the "Company") as of December 31, 2004 and 2003, and for each of the three years in the period ended December 31, 2004, management's assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2004. and the effectiveness of the Company's internal control over financial reporting as of December 31, 2004, and have issued our reports thereon dated February 28, 2005 (which report on the con-solidated financial statements expresses an unqualified opinion and includes an explanatory paragraph as to changes in accounting princi-ples in2003 for: asset retirement obligations, contracts involved inenergy trading, derivative contracts not held for trading purposes, derivative contracts with a price adjustment feature, the consolidation of variable interest entities, and guarantees); such reports are included elsewhere in this Annual Report on Form 10-K. Our audits also included the financial statement schedule of the Company listed in Item 15. This financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. Inour opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP Richmond, Virginia February 28, 2005 D 20041 Page 100

Dominion Resources, Inc. (Parent Company)

Schedule I-Condensed Financial Information of Registrant Condensed Statements of Income Year Ended December 31. 2004 2003 2002 (millionsl Operating Expenses Affiliated S 10 $ 22 $ 22 Other (5) 10 11 Total operating expense 5 32 33 Loss from operations (5) (32) (33)

Other income (expense):

Affiliated interest income 155 137 85 Other 4 128) 7 Total other income 159 109 92 Interest and related charges:

Affiliated interest expense 69 73 68 Other 376 408 353 Total interest and related charges 445 481 421 Loss before income taxes (291) (404) (362)

Income tax benefit 160 163 121 Equity inearnings of affiliates 1,395 1,201 1,603 Income from continuing operations 1,264 960 1,362 Loss from discontinued operations (net of income tax benefit of $4and expense of $15 in 2004 and 2003.

respectively) (15) (642) -

Net Income $1.249 $ 318 $1,362 The accompanying notes are an integral part of the Condensed Financial Statements.

D 2004 /Page 101

Dominion Resources, Inc. (Parent Company)

Schedule I-Condensed Financial Information of Registrant Condensed Balance Sheets AtDecembet 31, 2W4 2003 (millions)

ASSETS Current Assets Cash and cash equivalents $ 10 $ 9 Receivables and advances due from affiliates 2,858 2,831 Other accounts receivable 7 -

Prepayments 61 Total current assets 2,875 2,901 Investments Investment inaffiliates 14,474 14,543 Loans to affiliates 1,645 1,699 Other 39 32 Total investments 16,158 16,274 Property, Plant and Equipment, Net Property, plant and equipment 3 6 Accumulated depreciation, depletion and amortization - 13)

Total property. plant and equipment, net 3 3 Deferred Charges and Other Assets 125 37 Total assets $19,161 $19,215 LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities Securities due within one year $ 1,090 $ 268 Short-term debt 306 573 Payables and short-term borrowings due to affiliates 16 82 Accrued interest and taxes 129 108 Other 39 5 Total current liabilities 1,580 1,036 Long-Term Debt Long-term debt 5,284 6,069 Notes payable to affiliates 822 848 Total long-term debt 6,106 6,917 Deferred Credits and Other Liabilities 49 59 Total liabilities 7,735 8,012 Preferred Stock - 665 Common Shareholders' Equity Common stock, no parl 10,888 10,052 Other paid-in capital 92 61 Retained earnings 1,442 1,054 Accumulated other comprehensive loss (996) (629)

Total common shareholders' equity 11,426 10,538 Total liabilities and shareholders' equity $19,161 $19,215 (1)500 million shares authorized; 340 million shares and 325 million shares outstanding at December 31, 2004 and 2003, respectively.

The accompanying notes are an integral part of the Condensed Financial Statements. I D 2004/ Page 102

Dominion Resources, Inc. (Parent Company)

Schedule I-Condensed Financial Information of Registrant Condensed Statements of Cash Flows Year EndedDecember 31, 2004 2c03 2002 Imillions)

Net Cash Provided By Operating Activities $ 754 $ 690 $ 547 Investing Activities Investment in affiliates (527) (77) (95)

Affiliate (advances) repayment, net 64 (1.296) (2,435)

Loans to affiliates - (220)

Purchase of Dominion Fiber Ventures senior notes - (633)

Escrow release (deposit) for debt refunding - 500 (500)

Other - - 13)

Net cash used ininvesting activities (463) (1,726) (3,033)

Financing Activities Issuance of common stock 839 990 2.020 Repurchase of common stock - - (66)

Issuance of long-term debt 300 2,120 1,680 Repayment of long-term debt (268) (1,500) -

Issuance (repayment) of short-term debt, net (267) 219 (294)

Repayment of short-term borrowings from affiliates, net (24) - -

Repayment of notes payable to affiliates - (15) 1227)

Common dividends paid (861) (825) (723)

Other (9) (18) (11)

Net cash (used in)provided by financing activities (290) 971 2,379 Increase (decrease) in cash and cash equivalents 1 (65) 1107)

Cash and cash equivalents at beginning of the year 9 74 181 Cash and cash equivalents at end of the year $ 10 $ 9 $ 74 Supplemental Cash Flow Information:

Noncash transactions from investing and financing activities:

Conversion of short-term advances andother amounts receivable from subsidiaries to investment in subsidiaries .: $ 84 $ 1,220 $ 959 Return of preferred stock from beneficially owned trust 665 -

Forgiveness of Dominion Fiber Ventures, LLC notes receivable 644 -

Conversion of interest receivable from subsidiaries to long-term note receivable - 125 Subsidiary common stock received inexchange for reduction in amounts receivable from subsidiary - - 150 Exchange of cdebt securities 219 500 450 The accompanying notes are an integral part of the Condensed Financial Statements.

D2004 /Page 103

Dominion Resources, Inc. (Parent Company)

Schedule I -Condensed Financial Information of Registrant Notes to Condensed Financial Statements

1. Basis of Presentation Pursuant to rules and regulations of the Securities and Exchange Income Taxes-The Company and its subsidiaries file a con-Commission (SEC), the unconsolidated condensed financial state- solidated federal income tax return and participate inan inter-ments of Dominion Resources, Inc. (the Company) do not reflect all company tax allocation agreement. At December 31, 2004 and of the information and notes normally included with financial 2003, the Company's Balance Sheets include current taxes receiv-statements prepared in accordance with accounting principles able from affiliates of $32 million and current taxes payable to generally accepted inthe United States of America. Therefore, affiliates of $14 million, respectively. Under the 1935 Public Utility these financial statements should be read inconjunction with the Holding Company Act (1935 Act), the Company is restricted in consolidated financial statements and related notes included in the amount of cash reimbursements that it may receive from the 2004 Form 10-K, Part 11,Item 8. subsidiaries.

Accounting for subsidiaries-The Company has accounted for the earnings of its subsidiaries under the equity method inthe unconsolidated condensed financial statements.

2. Long-Term Debt 2004 Weighted average At December 31, Coupo00' 2004 2003 Unsecured Senior and Medium-Term Notes:

2.25% to 7.625%, due 2004 to 2008 4.85% S 2,002 $1,740 5.0% to 8.1 25%, due 2009 to 2033(z) 6.25% 3,880 3,680 Unsecured Equity-Linked Senior Notes, 5.75% due 2008 5.75% 330 743 Unsecured Convertible Senior Notes, 2.125%, due 2023(31 220 220 Unsecured Nonrecourse Debt:

Variable Rates, due 2004 - 18 6,432 6,401 Fair value hedge valuations4 - 2 2 Amount due within one year ' 5.85% 11,090) (268)

Unamortized discount . (60) 166) 5,284 6,069 Notes Payable-Affiliates:

Unsecured Other Affiliated Notes Payable, 6.0%, due 200515t - 26 Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% to 8.4%, due 2027 to 2041 8.22% 82.5 825 825 . 851 Amount due within one year Unamortized discount (3) (31 822 848 Total long-term debt S 6,106 $6,917 (11 Represents weighted-average coupon rates during 2004 for debt outstanding as Based on the stated maturity dates rather than the early of December 31, 2004.

redemption dates that could be elected by the instrument holders, (21 At the option of holders inAugust 2015, $510 million of Dominion's 5.25/

senior notes due 2033. are subject to redemption at 100% of the principal noted above, the scheduled principal payments of long-term at amount plus accrued interest. December 31, 2004 were as follows (inmillions):

(31Convertible into acombination of cash and Dominion's common stock at any time after March 31. 2004 when the average closing price of Dominion common 2005 2006 2007 2008 2009 Thereafter Total stock reaches $88.32 per share for aspecified period. At the option of holders on December 15, 2006, December 15, 2008, December 15, 2013, or December 15. $1,090 $512 $- $730 $300 $4,625 $7,257 2018, these securities are subject to redemption at 100% of the principal amount plus accrued interest. The Company's long-term debt agreements contain customary (41 Represents changes infair value of certain fixed rate long-term debt associated covenants and default provisions. As of December 31, 2004, there with fair value hedging relationships. were no events of default under those covenants.

(51Debt was redeemed inDecember 2004.

D 2004/Page 104

< > s

3. Guarantees, Letters of Credit and Surety Bonds make payments to compensate or indemnify other parties for Guarantees Supporting Related Parties possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse As of December 31, 2004. substantially all of the officers' judgment ina lawsuit or the imposition of additional taxes due to a borrowings under executive stock loan programs, which were change intax law or interpretation of the tax law. The Company is guaranteed by the Company, have been repaid. Because of unable to developan estimate of the maximum potential amount restrictions on corporate loans or guarantees for executives under of future payments under these contracts because events that the Sarbanes-Oxley Act of 2002, the Company has ceased its would obligate the Company have not yet occurred or, if any such program of third party loans to executives for the purpose of event has occurred, the Company has not been notified of its acquiring company stock.

occurrence. However, at December 31, 2004, management believes future payments, if any, that could ultimately become Guarantees Supporting Subsidiaries payable under these contract provisions, would not have a material As of December 31, 2004, the Company had issued the impact on its results of operations, cash flows or financial position.

following types of guarantees of behalf of its subsidiaries:

Amount 4. Dividend Restrictions (millions) The Company received dividends from its consolidated subsidiaries Subsidiary debtsl) $1,484 inthe amounts of $1.2 billion, $1.1 billion, and $945 million for the Commodity transactions(2) 2,345 years 2004, 2003, and 2002, respectively.

Lease obligation for power generation facility(3) 898 The 1935 Act and related regulations issued by the SEC impose Nuclear obligationst 41 509 USGen facilities15) 656 restrictions on the transfer and receipt of funds by a registered Miscellaneous 302 holding company from its subsidiaries, including a general prohib-ition against loans or advances being made by the subsidiaries to Total subsidiary obligations $6,194 benefit the registered holding company. Under the 1935 Act, regis-IIl Guarantees of debt of Dominion Resource Services Company IDRSI. and certain tered holding companies and their subsidiaries may pay dividends Dominion Energy. Inc. (DEI) and Consolidated Natural Gas Company (CNGI sub- only from retained earnings, unless the SEC specifically authorizes sidiaries. Inthe even: of default by the subsidiaries, the Company would be payments from other capital accounts. Inresponse to the Compa-obligated to repay such amounts.

121 Guarantees related to energy marketing activities and other commodity commit- ny's request, the SEC granted relief in2000, authorizing payment ments of certain subsidiaries of Virginia Electric and Power Company (Virginia of dividends by CNG from other capital accounts to the Company in Power), CNG and DEI. These guarantees were provided to counterparties inorder amounts up to $1.6 billion, representing CNG's retained earnings.

to facilitate physical and financial transactions ingas, oil, electricity, pipeline capacity, transportation and related commodities and services. Ifany one of prior to the Company's acquisition of CNG. The SEC granted further these subsidiaries fails to perform or pay under the contracts and the counter- relief in2004, authorizing the Companys nonutility subsidiaries to parties seek performance or payment, the Company would be obligated to satisfy pay dividends out of capital or unearned surplus in situations such obligation. The Company and its subsidiaries receive similar guarantees as collateral for credit extended to others. where such subsidiary has received excess cash from an asset (31Guarantee of aleasing obligation of a DEI subsidiary for anew power gen- sale, engaged ina restructuring, or is returning capital to an asso-eration facility. ciate company. The Company's ability to pay dividends on its (41 Guarantees related to the future nuclear decommissioning obligations of Virginia Power and certain DOEI subsidiaries and potential retrospective premiums that common stock at declared rates was not impacted by the could be assessed, if there isanuclear incident under the Company's nuclear restrictions discussed above during 2004, 2003 and 2002.

insurance programs. Also, as part of satisfying certain Nuclear Regulatory - The Virginia State Corporation Commission (Virginia Commis-Commission requirements concerned with ensuring adequate funding for the operations of the Millstone Power Station, the Company has also agreed to- sion) may prohibit any public service company, including Virginia provide up to S156nillion to aDElsubsidiary, if requested by such subsidiary, to Power, from declaring or paying a dividend to an affiliate, if found pay Millstone's operating expenses. Also includes guarantees for Virginia Pow- not to be inthe public interest. At December 31, 2004, the Virginia er's commitment to buy nuclear fuel.

151 Guarantee associated with asubsidiary's commitment to purchase three electric Commission had not restricted the payment of dividends by generating facilities from uSGen New England, Inc. The guarantee expired when Virginia Power.

the acquisition was completed on January 1.2005. Certain agreements associated with the Company's credit facili-Surety Bonds and Letters of Credit ties contain restrictions on the ratio of debt to total capitalization.

These limitations did not restrict the Company's ability to pay At December 31, 2004, the Company had purchased $17 million dividends or receive dividends from its subsidiaries at of surety bonds and authorized the issuance of standby letters of December 31, 2004.

credit by financial institutions of $182 million. The Company enters See Note 17 to the Consolidated Financial Statements included into these arrangements to facilitate commercial transactions by in the 2004 Form 10-K, Part II, Item 8., for a description of potential its subsidiaries with third parties. As of December 31, 2004, no restrictions on dividend payments by the Company and certain amounts had been presented for payment under the letters of subsidiaries inconnection with the deferral of distribution pay-credit.

ments on trust preferred securities.

Indemnifications In addition, as part of commercial contract negotiations in the normal course of business, the Company may sometimes agree to D 2004 /Page 105

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.

DOMINION RESOURCES, INC.

By: /s/ THOS. E.CAPPS (Thos. E Capps. Chairman of the Board of Directors and Chief Executive Officer)

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

Signature Title

/s/ THos. E.CAPPS Chairman of the Board of Directors and Chief Executive Officer Thos. E. Capps

/s! PETER W. BROWN Director Peter W. Brown

/sf RONALD J. CAUSE Director Ronald J. Callse Is/ GEORGE A. DAVIDSON, JR. Director George A. Davidson, Jr.

Is/ JOHN W, HARRIS Director John W. Harris

/s/ ROBERT S. JEPSON, JR. Director Robert S. Jepson, Jr.

Is! BENJAMIN J. LAMBERT, IlIl Director Benjamin J. Lambert, HI Isl RICHARD L. LEATHERWOOD Director Richard L. Leatherwood

/s/ MARGARET A. McKENNA Director Margaret A. McKenna

/s/ K.A. RANDALL Director K. A. Randall

/s/ FRANK S.ROYAL Director Frank S. Royal

/S/ S.DALLAS SIMMONS Director S. Dallas Simmons

/s/ DAVIo A. WOLLARD Director David A. Wollard

/sf THOMAS N.CHEWNING Executive Vice President and Chief Financial Officer Thomas N. Chewning

/s/ STEVEN A. ROGERS Vice President, Controller and Principal Accounting Officer Steven A. Rogers D 2004/ Page 106