SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2004

¨	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 1-3196

CONSOLIDATED NATURAL GAS COMPANY

(Exact name of registrant as specified in its charter)


Delaware		54-1966737
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

120 Tredegar Street Richmond, Virginia		23219
(Address of principal executive offices)		(Zip Code)

(804) 819-2000

(Registrant’s telephone number)

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


Title of Each Class		Name of Each Exchange on Which Registered
6.0% Debentures due 2010		New York Stock Exchange
6.8% Debentures due 2027		New York Stock Exchange
6⁵/8% Debentures due 2008		New York Stock Exchange
6⁷/8% Debentures due 2026		New York Stock Exchange
7³/8% Debentures due 2005		New York Stock Exchange
6⁵/8% Debentures due 2013		New York Stock Exchange
7.8% 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 (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

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

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

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

As of February 1, 2005, there were issued and outstanding 100 shares of the registrant’s common stock, without par value, all of which were held, beneficially and of record, by Dominion Resources, Inc.

THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I.(1)(a) AND (b) OF FORM 10-K AND IS FILING THIS FORM 10-K UNDER THE REDUCED DISCLOSURE FORMAT.

Consolidated Natural Gas Company


Item Number		Page Number
Part I
1.	Business	1
2.	Properties	6
3.	Legal Proceedings	8
4.	Submission of Matters to a Vote of Security Holders	8

Part II
5.	Market for the Registrant’s Common Equity and Related Stockholder Matters	9
6.	Selected Financial Data	9
7.	Management’s Discussion and Analysis of Results of Operations	9
7A.	Quantitative and Qualitative Disclosures About Market Risk	19
8.	Financial Statements and Supplementary Data	20
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	53
9A.	Controls and Procedures	53
9B.	Other Information	53

Part III
10.	Directors and Executive Officers of the Registrant	54
11.	Executive Compensation	54
12.	Security Ownership of Certain Beneficial Owners and Management	54
13.	Certain Relationships and Related Transactions	54
14.	Principal Accountant Fees and Services	54

Part IV
15.	Exhibits and Financial Statement Schedules	55

Part I

Item 1. Business

The Company

Consolidated Natural Gas Company (CNG or the Company) operates in all phases of the natural gas business, explores for and produces oil, and provides a variety of retail energy marketing services. The Company is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion), a fully integrated gas and electric holding company headquartered in Richmond, Virginia. The Company is a public utility holding company registered under the Public Utility Holding Company Act of 1935 (1935 Act).

The “Company” is used throughout this report and, depending on the context of its use, refers to CNG, one of CNG’s consolidated subsidiaries, or the entirety of CNG and its consolidated subsidiaries, both before and after the merger with Dominion.

As of December 31, 2004, the Company had approximately 4,600 full-time employees. Approximately 2,500 employees are subject to collective bargaining agreements. The contract of employees represented by the Utility Workers’ Union of America, United Gas Workers’ Local 69-11, AFL-CIO (Local 69-II) expires April 1, 2005. The Company and Local 69-II have begun negotiations for a new contract.

The Company was incorporated in Delaware in 1999. The Company’s principal executive offices are located at 120 Tredegar Street, Richmond, Virginia 23219 and its telephone number is (804) 819-2000.

Operating Segments

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

Delivery

Delivery includes the Company’s regulated gas distribution utilities and customer service operations as well as retail energy marketing operations. Gas distribution operations serve residential, commercial and industrial gas sales and transportation customers in Ohio, Pennsylvania and West Virginia. Retail energy marketing operations include the marketing of gas, electricity and related products and services to residential and small commercial customers in the Northeast, Mid-Atlantic and Midwest regions.

Competition

Deregulation is at varying stages in the three states in which the Company’s gas distribution subsidiaries operate. In Pennsylvania, supplier choice is available for all residential and small commercial customers. In Ohio, legislation has not been enacted to require supplier choice for residential and commercial natural gas consumers. However, the Company offers an Energy Choice program to customers on its own initiative, in cooperation with the Public Utilities Commission of Ohio (Ohio Commission). West Virginia does not require customer choice in its retail natural gas markets at this time. See Regulation—State Regulations for additional information.

Regulation

The Company’s gas distribution service, including the rates it may charge to customers, is regulated by the Ohio Commission, the Pennsylvania Public Utility Commission (Pennsylvania Commission) and the West Virginia Public Service Commission (West Virginia Commission). See Regulation—State Regulations for additional information.

Properties

Delivery’s investment in its gas distribution network is located in the states of Ohio, Pennsylvania and West Virginia. The gas distribution network includes approximately 27,000 miles of pipe, exclusive of service pipe and 203 billion cubic feet (bcf) of underground storage capacity in Ohio, Pennsylvania and West Virginia. See Energy—Properties for additional information regarding Delivery’s storage properties.

Sources of Fuel Supply

Delivery is engaged in the sale and storage of natural gas through its operating subsidiaries. Delivery’s natural gas supply for its operations is obtained from various sources including: purchases from major and independent producers in the Mid-Continent and Gulf Coast regions; purchases from local producers in the Appalachian area; purchases from gas marketers; and withdrawals from the Company’s and third party underground storage fields.

Seasonality

Gas sales in the Delivery segment typically vary seasonally based on demand by residential and commercial customers for heating use due to changes in temperature.

Energy

Energy includes the following operations:

•

A regulated interstate gas transmission pipeline and storage system, serving the Company’s gas distribution businesses and other customers in the Midwest, the Mid-Atlantic states and the Northeast;

•

A liquefied natural gas (LNG) import and storage facility in Maryland;

•

Certain natural gas production operations located in the Appalachian basin; and

2004 / Page 1

•

Producer services operations, representing aggregation of gas supply and associated wholesale activities related to the Appalachian area.

Competition

The Energy segment competes with domestic and Canadian pipeline companies and gas marketers to provide or arrange transportation, storage and other services for customers. Alternative energy sources, such as oil or coal, provide another level of competition. Although competition is based primarily on price, the array of services that can be provided to customers is also an important factor. The combination of capacity rights held on certain longline pipelines, a large storage capability and the availability of numerous receipt and delivery points along its own pipeline system enables the Company to tailor its services to meet the needs of individual customers.

Regulation

Energy’s natural gas transmission, storage and LNG operations are subject to regulation by the Federal Energy Regulatory Commission (FERC). See Regulation—Federal Regulations for additional information.

Properties

Energy has approximately 7,900 miles of gas transmission, gathering and storage pipelines located in the states of Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia.

The Company’s storage operations involve both the Delivery and Energy segments. Storage operations include 26 underground gas storage fields located in New York, Ohio, Pennsylvania and West Virginia, with more than 2,000 storage wells and approximately 372,000 acres of operated leaseholds. The Energy and Delivery segments together have more than 100 compressor stations with approximately 626,000 installed compressor horsepower. The total designed capacity of the underground storage fields is approximately 965 billion cubic feet (bcf) of which 203 bcf is operated by Delivery and 762 bcf is operated by Energy. Six of the 26 storage fields are jointly-owned with other companies and have a capacity of 243 bcf. Energy also has approximately 8 bcf of above ground storage capacity at its Cove Point liquefied natural gas facility.

The map below illustrates the Company’s gas transmission pipelines, storage facilities and LNG facility.

LOGO

Sources of Energy Supply

The Company’s large underground natural gas storage network and the location of its pipeline system provide a significant link between the country’s major gas pipelines and large markets in the Northeast and Mid-Atlantic regions and on the East Coast. The Company’s pipelines are part of an interconnected gas transmission system which continues to provide local distribution companies, marketers, power generators and commercial and industrial customers accessibility to supplies nationwide.

The Company’s underground storage facilities play an important part in balancing gas supply with consumer demand and are essential to serving the Midwest, Mid-Atlantic and Northeast’s regions. In

2004 / Page 2

addition, storage capacity is an important element in the effective management of both gas supply and pipeline transport capacity.

Seasonality

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

Exploration & Production

Exploration & Production includes the Company’s gas and oil exploration, development and production operations. These operations are located in several major producing basins in the lower 48 states, including the outer continental shelf and deepwater areas of the Gulf of Mexico.

Competition

Exploration & Production’s competitors range from major international oil companies to smaller independent producers. Exploration & Production faces significant competition in the bidding for federal offshore leases and in obtaining leases and drilling rights for onshore properties. Since Exploration & Production is the operator of a number of properties, it also faces competition in securing drilling equipment and supplies for exploration and development.

In terms of its production activities, Exploration & Production sells most of its deliverable natural gas and oil into short and intermediate-term markets. Exploration & Production faces challenges related to the marketing of its natural gas and oil production due to the contraction of participants in the energy marketing industry. However, Exploration & Production owns a large and diverse natural gas and oil portfolio and maintains an active gas and oil marketing presence in its primary production regions which strengthens its knowledge of the marketplace and delivery options.

Regulation

The Company’s operations are subject to regulation by numerous federal and state authorities. The pipeline transportation of the Company’s natural gas production is regulated by FERC, and pipelines operating on or across the Outer Continental Shelf are subject to the Outer Continental Shelf Lands Act, which requires open-access, non-discriminatory pipeline facilities. The Company’s production operations in the Gulf of Mexico and most of its operations and in the western United States are located on federal gas and oil leases administered by the Minerals Management Service (MMS) or the Bureau of Land Management. These leases are issued through a competitve bidding process and require the Company’s compliance with stringent regulations. Offshore production facilities must comply with MMS regulations relating to engineering, construction and operational specifications and the plugging and abandonment of wells. The Company’s operations are also subject to numerous environmental regulations including regulations relating to oil spills into navigable waters of the United States. See Regulation - Federal Regulations and Regulation—Environmental Regulation for additional information.

Properties

Exploration & Production owns 5.1 trillion cubic feet of proved equivalent natural gas reserves and produces approximately .9 billion cubic feet of equivalent natural gas per day from its leasehold acreage and facility investments. The Company, either alone or with partners, holds interests in natural gas and oil lease acreage, wellbores, well facilities, production platforms and gathering systems. Exploration & Production also owns or holds rights to seismic data and other tools used in exploration and development drilling activities. Exploration & Production’s share of developed leasehold totals 2.3 million acres, with another 1.7 million acres held for future exploration and development drilling opportunities. See also Item 2. Properties for additional information on Exploration & Production’s properties.

LOGO

Note:

Includes the activities of the Exploration & Production segment and the production activity of Dominion Transmission, Inc., which is included in the Energy segment.

Bcfe = billion cubic feet equivalent

Mmcfe = million cubic feet equivalent

2004 / Page 3

Seasonality

Exploration & Production’s business can be impacted by seasonal changes in the demand for natural gas and oil. Commodity prices, including prices for the Company’s unhedged natural gas and oil production, can be impacted by seasonal weather changes and weather effects.

Corporate and Other

The Company also has a Corporate and Other segment. Corporate and Other includes the activities of CNG International (CNGI) and other minor subsidiaries, as well as costs of the Company’s corporate functions. It also includes specific items attributable to the Company’s operating segments that are reported in Corporate and Other. CNGI was engaged in energy-related activities primarily outside of the United States. However, the Company has decided to focus on the United States gas and oil markets and, accordingly, has sold the majority of CNG International’s assets (see Note 7 to the Consolidated Financial Statements). This segment also includes the results of the Company’s power generating facility.

Regulation

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

State Regulations

The Company’s gas distribution service is regulated by the Ohio Commission, the Pennsylvania Commission and the West Virginia Commission.

Status of Gas Deregulation

Each of the three states in which the Company has gas distribution operations has enacted or considered legislation regarding deregulation of natural gas sales at the retail level.

Ohio—Ohio has not enacted legislation requiring supplier choice for residential and commercial natural gas consumers. However, in cooperation with the Ohio Commission, the Company on its own initiative offers retail choice to customers. At December 31, 2004, approximately 548,000 of the Company’s 1.2 million Ohio customers were participating in this open-access program. Large industrial customers in Ohio also source their own natural gas supplies.

Pennsylvania—In Pennsylvania, supplier choice is available for all residential and small commercial customers. At December 31, 2004, approximately 88,000 residential and small commercial customers had opted for Energy Choice in the Company’s Pennsylvania service area. Nearly all Pennsylvania industrial and large commercial customers buy natural gas from nonregulated suppliers.

West Virginia—At this time, West Virginia has not enacted legislation to require customer choice in its retail natural gas markets. However, the West Virginia Commission has issued regulations to govern pooling services, one of the tools that natural gas suppliers may utilize to provide retail customer choice in the future and has issued rules requiring competitive gas service providers be licensed in West Virginia.

Rate Matters—Gas Distribution

The Company’s gas distribution business subsidiaries are subject to regulation of rates and other aspects of their businesses by the states in which they operate—Pennsylvania, Ohio and West Virginia. When necessary, the Company’s gas distribution subsidiaries seek general rate increases on a timely basis to recover increased operating costs. In addition to general rate increases, certain of the Company’s gas distribution subsidiaries make routine separate filings with their respective state regulatory commissions to reflect changes in the costs of purchased gas. These purchased gas costs are generally subject to rate recovery through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas cost recovery filings generally cover prospective one, three or twelve-month periods. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.

Ohio— In December 2003, the Ohio Commission approved a joint application filed by the Company and several other Ohio natural gas companies for recovery of bad debt expense via a rider known as a bad debt tracker. The tracker insulates the Company from the effect of changes in bad debt expense, which is affected by the volatility of natural gas prices, weather and prices charged by competitive retail natural gas suppliers. The tracker is an adjustable rate that recovers the cost of bad debt in a manner similar to a gas cost recovery rate. Instead of recovering bad debt costs through its base rates, the Company recovers all eligible bad debt expenses through the bad debt tracker and removes bad debt from base rates. Annually, the Company assesses the need to adjust the tracker based on the preceding year’s actual bad debt expense.

Pennsylvania— In July 2004, the Pennsylvania Commission approved a settlement agreement between the Company and the Office of Consumer Advocate (OCA) in which the OCA agreed to drop its appeal of a previous Pennsylvania Commission order that allowed the Company to recover approximately $16.5 million in unrecovered purchased gas costs. As part of the settlement, all customer service and delivery charges will be fixed through December 31, 2008. Gas costs will continue to pass through to the customer through the purchased gas cost adjustment mechanism.

Federal Regulations

Public Utility Holding Company Act of 1935

The Company is a registered holding company under the 1935 Act. The 1935 Act and related regulations issued by the SEC govern activities of the Company and its subsidiaries with respect to the issuance and acquisition of securities, acquisition and sale of utility assets, certain transactions among affiliates, engaging in business activities not directly related to the utility or energy business and other matters.

Federal Energy Regulatory Commission

FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the

2004 / Page 4

Natural Gas Policy Act of 1978, as amended. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by the Company’s interstate gas pipeline subsidiaries, including Dominion Transmission, Inc. (DTI) and Dominion Cove Point LNG, LP. FERC also has jurisdiction over siting, construction and operation of natural gas import facilities and interstate natural gas pipeline facilities.

FERC Order 636 requires transmission pipelines to operate as open-access transporters and provide transportation and storage services on an equal basis for all gas suppliers, whether purchased from the Company or from another gas supplier.

The Company’s interstate gas transportation and storage activities are conducted in accordance with certificates, tariffs and service agreements on file with FERC.

The Company is also subject to the Pipeline Safety Act of 2002, which includes new mandates regarding the inspection frequency for interstate and intrastate natural gas transmission and storage pipelines located in areas of high-density population where the consequences of potential pipeline accidents pose the greatest risk to people and their property. The Company has evaluated its natural gas transmission and storage properties under the final regulations issued in December 2003 and has developed the required implementation plan including identification, testing and potential remediation activities.

The Company is also subject to FERC’s Standards of Conduct that govern conduct between interstate transmission gas and electricity providers and their marketing function or their energy related affiliates. The rule defines the scope of the affiliates covered by the standards and is designed to prevent transmission providers from giving their marketing functions or affiliates undue preferences.

In August 2004, the Company and FERC announced a settlement of a self-reported infraction of FERC regulations involving data sharing of non-public gas storage information. Under the settlement, the Company paid a $500,000 civil penalty and refunded $4.5 million to its non-affiliated natural gas storage customers. In addition the Company agreed to enhance internal training and oversight of employees who handle non-public, market-sensitive data.

The Company implemented various rate filings, tariff changes and negotiated rate service agreements for its FERC-regulated businesses during 2004. In all material respects, these filings were approved by FERC in the form requested by the Company and were subject to only minor modifications.

At the request of the Public Service Commission of the State of New York (PSCNY), DTI has engaged in negotiations with PSCNY regarding the potential for a prospective reduction of DTI ‘s transportation and storage service rates to address concerns about the level of DTI’s earnings. As a result of these negotiations, DTI and PSCNY have reached an agreement in principle that establishes parameters for a potential rate settlement, which must be finalized by DTI and its customers. DTI is negotiating with its customers to reach a possible settlement agreement. The settlement parameters envision reduced rates to DTI’s customers and a five-year moratorium on future changes to DTI’s transportation and storage service rates. If DTI is able to reach an agreement with its customers during the first quarter of 2005, FERC approval of a filed settlement could be obtained during the second quarter.

Environmental Regulation

Each operating segment faces substantial regulation and compliance costs with respect to environmental matters. For a discussion of significant aspects of these matters, see Item 3. Legal Proceedings and Note 19 to the Consolidated Financial Statements.

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

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

2004 / Page 5

Item 2. Properties

The Company shares its principal office in Richmond, Virginia, with its parent company, Dominion. Such office space is leased. The Company leases offices in other cities in which its subsidiaries operate. The Company’s assets consist primarily of its investments in its subsidiaries, the principal properties which are described below and in Item 1. Business.

Information detailing the Company’s gas and oil operations presented below includes the activities of the Exploration & Production segment and the production activity of Dominion Transmission, Inc. (DTI), which is included in the 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 Developed	Total Proved	Proved Developed	Total Proved	Proved Developed	Total Proved
Proved gas reserves (bcf)	3,131	4,286	2,971	4,112	2,869	3,662
Proved oil reserves (000 bbl)	87,181	128,723	42,150	135,717	47,290	138,328
Total proved gas and oil reserves (bcfe)	3,654	5,058	3,224	4,927	3,153	4,492

Certain subsidiaries of the Company file Form EIA-23 with the DOE, which reports gross proved reserves, including the working interests share of other owners, for properties operated by such Company subsidiaries. The proved reserves reported in the table above represent the Company’s share of proved reserves for all properties, based on the Company’s ownership interest in each property. For properties operated by the Company, the difference between the proved reserves reported on Form EIA-23 and the gross reserves associated with the Company-owned proved reserves reported in the table above, does not exceed five percent. Estimated proved reserves as of December 31, 2004 are based upon a study for each of the Company’s properties prepared by the Company’s staff engineers and reviewed by either Ralph E. Davis Associates, Inc. or Ryder Scott Company, L.P. Calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance 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 (bcf)	278	292	286
Oil production (000 bbls)	8,772	7,574	8,537
Total gas and oil production (bcfe)	331	337	337

The average sales price per thousand cubic feet (mcf) of gas with hedging results (including transfers to other Company oper-ations at market prices) realized during the years 2004, 2003 and 2002 was $4.19, $4.15 and $3.60, respectively. The respective average prices without hedging results per mcf of gas produced were $5.83, $5.26 and $3.25, respectively. The respective average sales prices realized for oil with hedging results were $24.51, $24.80 and $23.73 per barrel and the respective average prices without hedging results were $39.96, $30.74 and $25.03 per bar-rel. 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 $0.78, $0.75 and $0.51 respectively.

2004 / Page 6

Acreage

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


	Developed Acreage		Undeveloped Acreage
(thousands)
	Gross	Net	Gross	Net
Acreage	3,711	2,295	2,951	1,685

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:
Productive	7	4	12
Dry	7	7	12
Total Exploratory	14	11	24
Development:
Productive	830	719	665
Dry	17	33	38
Total Development	847	752	703
Total wells drilled (net)	861	763	727

As of December 31, 2004, 111 gross (79 net) wells were in process of being drilled, including wells temporarily suspended.

Productive Wells

The number of productive gas and oil wells in which the Company had an interest at December 31, 2004, follows:


	Gross	Net
Total gas wells	19,865	13,125
Total oil wells	985	497

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.

2004 / Page 7

Item 3. Legal Proceedings

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

See Regulation in Item 1. Business and Note 19 to the Consolidated Financial Statements for additional information on rate matters and various regulatory proceedings to which the Company is a party.

Before being acquired by the Company, Louis Dreyfus Natural Gas Corp. (Louis Dreyfus) was one of numerous defendants in a lawsuit consolidated and now pending in the 93rd Judicial District Court in Hidalgo County, Texas. The lawsuit alleges that gas wells and related pipeline facilities operated by Louis Dreyfus, and other facilities operated by other defendants, caused an underground hydrocarbon plume in McAllen, Texas. The plaintiffs claim that they have suffered damages, including property damage and lost profits, as a result of the alleged plume and seek compensation for these items.

In July 1997, Jack Grynberg, an oil and gas entrepreneur, brought suit against CNG and several of its subsidiaries. The suit seeks damages for alleged fraudulent mismeasurement of gas volumes and underreporting of gas royalties from gas production taken from federal leases. The suit was consolidated with approximately 360 other cases in the 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.

In April 1998, Harrold E. (Gene) Wright, an oil and gas entrepreneur, brought suit against Dominion Exploration & Production, Inc. (formerly known as CNG Producing Company), a subsidiary of CNG, alleging various fraudulent valuation practices in the payment of royalties on federal leases. Shortly after filing, this case was consolidated under the Federal Multidistrict Litigation rules with the Grynberg case noted above. A substantial portion of the claim against CNG Producing Company was resolved by settlement in late 2002. The case was remanded back to the U.S. District Court for the Eastern District of Texas, which denied the defendant’s motion to dismiss on jurisdictional grounds in January 2005. Discovery may begin in the matter in the spring of 2005.

In August 2004, DTI received a proposed Consent Order and Agreement (COA) from the Pennsylvania Department of Environmental Protection (PADEP) which would supersede a 1990 COA between the parties. The proposed COA would resolve groundwater contamination issues at several DTI compressor stations in Pennsylvania. The draft COA proposes penalties to be paid to PADEP and the Pennsylvania Department of Conservation and Natural Resources to resolve alleged violations. The proposed COA has not been accepted by DTI and is subject to ongoing negotiations with the agencies. Management believes that the ultimate resolution of the COA will not have a material effect on the Company.

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

Omitted pursuant to General Instruction I.(2)(c).

2004 / Page 8

Part II

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

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

The Company paid quarterly cash dividends on its common stock as follows (in millions):


	Quarter
	First		Second		Third		Fourth
2004	$	183	$	88	$	70	$	141
2003		166		79		71		134

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

Item 6. Selected Financial Data

Omitted pursuant to General Instruction I.(2)(a).

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

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

Contents of MD&A

The reader will find the following information in this MD&A:

•

Forward-Looking Statements

•

Introduction

•

Accounting Matters

•

Results of Operations

•

Segment Results of Operations

•

Credit Risk

•

Risk Factors and Cautionary Statements That May Affect Future Results

Forward-Looking Statements

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

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

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

Introduction

CNG is a public utility holding company registered under the Public Utility Holding Company Act of 1935 (1935 Act). The Company, through its subsidiaries, operates in all phases of the natural gas business, explores for and produces gas and oil and provides a variety of energy marketing services.

The Company is organized primarily on the basis of products and services sold in the United States. The Company manages its operations through three primary operating segments: Energy, Delivery and Exploration & Production. The contributions to net income by the Company’s primary operating segments are determined based upon a measure of profit that executive management believes represents the segments’ core earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by executive management in assessing segment performance or allocating resources among the segments. Those specific items are reported in the Corporate and Other segment.

Energy includes the following operations:

•

A regulated interstate gas transmission pipeline and storage system, serving the Company’s gas distribution businesses and other customers in the Midwest, the Mid-Atlantic states and the Northeast;

•

A liquefied natural gas (LNG) import and storage facility in Maryland;

•

Certain natural gas production operations located in the Appalachian basin; and

•

Producer services operations, representing aggregation of gas supply and associated wholesale activities related to the Appalachian area.

Energy’s revenue and cash flows are derived from both regulated and nonregulated operations. Revenue and cash flow provided by gas transmission operations and the LNG facility are

2004 / Page 9

based primarily on cost-of-service rates established by the Federal Energy Regulatory Commission (FERC). Variability in revenue and cash flow provided by these regulated businesses results primarily from changes in rates and the demand for services. Variability in expenses relates largely to operating and maintenance expenditures, including decisions regarding the use of resources for operations and maintenance or capital-related activities.

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

Delivery includes the Company’s regulated gas distribution utilities and customer service operations as well as retail energy marketing operations. Gas distribution operations serve residential, commercial and industrial gas sales and transportation customers in Ohio, Pennsylvania and West Virginia. Retail energy marketing operations include the marketing of gas, electricity and related products and services to residential and small commercial customers in the Northeast, Mid-Atlantic and Midwest.

Revenue and cash flow provided by the Company’s gas distribution utility operations are based primarily on cost-of-service rates established by state regulatory authorities and state law. Variability in Delivery’s revenue and cash flow relates largely to changes in volumes, which are primarily weather sensitive. In addition, for distribution utility operations, revenue may vary based on changes in levels of rate recovery for the cost of gas purchased and sold to customers. Such costs and recoveries generally offset and do not materially impact net income. Revenue from retail marketing operations may vary in connection with changes in weather and commodity prices as well as the acquisition and potential loss of customers.

Sales growth in the regulated residential service areas of Ohio, Pennsylvania and West Virginia has generally been limited since these areas have experienced minimal population growth, and the vast majority of households in these areas already use natural gas for space heating. Sales are also being affected by regulatory and legislative initiatives to deregulate natural gas at the retail level. Under open access programs in Ohio and Pennsylvania, customers may choose a gas supplier other than their local gas utility and have the local utility provide transportation of the commodity through its existing delivery system. Delivery’s retail energy marketing businesses currently have gas customers in Ohio, Pennsylvania and Illinois.

Large industrial customers in Ohio source their own natural gas supplies. Nearly all Pennsylvania industrial and large commercial customers buy natural gas from nonregulated suppliers.

Variability in expenses results from changes in the cost of purchased gas and routine maintenance and repairs (including labor and benefits as well as decisions regarding the use of resources for operations and maintenance or capital-related activities). For gas distribution utility operations, the Company is permitted to seek recovery of the cost of gas purchased and sold to customers.

Exploration & Production includes the Company’s gas and oil exploration, development and production operations. These operations are located in several major producing basins in the lower 48 states, including the outer continental shelf and deepwater areas of the Gulf of Mexico.

The Company maintains an active and ongoing drilling program focused on low risk development drilling in several proven onshore regions of the United States, while also maintaining some exposure to higher risk exploration opportunities. Significant development drilling programs are currently underway in West Texas, the Appalachians and the Rocky Mountains where the Company holds sizeable acreage positions and operational experience. While each region provides the Company with exploration opportunities, most exploratory drilling takes place in the Gulf Coast region, including the deepwater Gulf of Mexico.

Revenue and cash flow provided by exploration and production operations are based primarily on the production and sale of company-owned natural gas and oil reserves. Variability in the segment’s revenue and cash flow relates primarily to changes in commodity prices, which are market based, and volumes, which are impacted by numerous factors including drilling success, timing of development projects, as well as external factors such as the storm-related damage caused by Hurricane Ivan. The Company manages commodity price volatility by hedging a substantial portion of its near term expected production.

Variability in the segment’s expenses relates primarily to changes in operating costs and production taxes, which tend to increase or decrease with changes in gas and oil prices and the prevailing cost environment. Commodity price changes place upward or downward pressure on related exploration and production service industry costs, while severance and property taxes vary based on changes in revenue. A changing price environment impacts both operating costs and the cost of acquiring, finding and developing natural gas and oil reserves.

Corporate and Other includes the activities of CNG International (CNGI), the Company’s power generating facility, and other minor subsidiaries, as well as costs of the Company’s corporate functions. It also includes specific items attributable to the Company’s operating segments that are reported in Corporate and Other. CNGI was engaged in energy-related activities primarily outside of the United States. However, the Company has decided to focus on the United States gas and oil markets and, accordingly, has sold the majority of CNGI’s assets (see Note 7 to the Consolidated Financial Statements).

Accounting Matters

Critical Accounting Policies and Estimates

The Company has identified the following accounting policies, including certain inherent estimates, that as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and operations involved, could result in material changes to its financial condition or results of operations

2004 / Page 10

under different conditions or using different assumptions. Management has discussed the development, selection and disclosure of each of these with the Company’s Audit Committee.

Accounting for derivative contracts at fair value

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

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

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

Use of estimates in goodwill impairment testing

As of December 31, 2004, the Company reported $623 million of goodwill on its Consolidated Balance Sheet. The majority of this goodwill is allocated to the Exploration & Production reporting unit, with the remainder allocated to the Energy reporting unit. In April of each year, the Company tests its goodwill for potential impairment, and performs additional tests more frequently if impairment indicators are present. The 2004 annual test did not result in the recognition of any impairment of goodwill, as the estimated fair values of the Company’s reporting units exceeded their respective carrying amounts.

The Company estimates the fair value of its reporting units by using a combination of discounted cash flow analyses, based on its internal five-year strategic plan, and other valuation techniques that use multiples of earnings for peer group companies and analyses of recent business combinations involving peer group companies. These calculations are dependent on subjective factors such as management’s estimate of future cash flows, the selection of appropriate discount and growth rates, and the selection of peer group companies and recent transactions. These underlying assumptions and estimates are made as of a point in time; subsequent modifications, particularly changes in discount rates or growth rates inherent in management’s estimates of future cash flows, could result in a future impairment of goodwill. Although the Company has consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows, and based those estimates on relevant information available at the time, such cash flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in the 2004 annual test had been 10% lower, the resulting fair values would have still been greater than the carrying values of each of those reporting units, indicating no impairment was present.

Employee benefit plans

The Company sponsors and also participates in certain Dominion noncontributory defined benefit pension plans and other postretirement benefit plans for eligible active employees, retirees and qualifying dependents. The costs of providing benefits under these plans are dependent, in part, on historical information such as employee demographics, the level of contributions made to the plans and earnings on plan assets. Assumptions about the future, including the expected rate of return on plan assets, discount rates applied to benefit obligations and the anticipated rate of increase in health care costs and participant compensation, also have a significant impact on employee benefit costs. The impact on pension and other postretirement benefit plan obligations associated with changes in these factors is generally recognized in the Consolidated Statements of Income over the remaining average service period of plan participants rather than immediately.

The selection of expected long-term rates of return on plan assets, discount rates and medical cost trend rates are critical assumptions. The Company determines the expected long-term rates of return on plan assets for pension plans and other postretirement benefit plans by using a combination of:

•

Historical return analysis to determine expected future risk premiums;

•

Forward-looking return expectations derived from the yield on long-term bonds and the price earnings ratios of major stock market indices;

•

Expected inflation and risk-free interest rate assumptions; and

•

Investment allocation of plan assets. The Company’s strategic target asset allocation for its pension fund is 45% U.S. equity securities, 8% non-U.S. equity securities, 22% debt securities and 25% other, such as real estate and private equity investments.

Assisted by an independent actuary, management develops assumptions, which are then compared to the forecasts of other independent investment advisors to ensure reasonableness. An internal committee selects the final assumptions. The Company calculated its pension cost using an expected return on plan assets

2004 / Page 11

assumption of 8.75% for 2004 and 2003. The Company calculated its other postretirement benefit cost using an expected return on plan assets assumption of 8.0% for 2004 and 2003. The rate used in calculating other postretirement benefit cost is lower than the rate used in calculating pension cost because of differences in the relative amounts of various types of investments held as plan assets and because other postretirement benefit activity, unlike the pension activity, is partially taxable.

Discount rates are determined from analyses performed by a third party actuarial firm of AA/Aa rated bonds with cash flows matching the expected payments to be made under the Company’s plans. Due to declines in bond yields and interest rates, the Company reduced the discount rate used to calculate 2004 pension and other postretirement benefit cost to 6.25% from the 6.75% discount rate that the Company used to calculate 2003 pension and other postretirement benefit cost.

The medical cost trend rate assumption is established based on analyses performed by a third party actuarial firm of various factors including the specific provisions of the Company’s medical plans, actual cost trends experienced and projected, and demographics of plan participants. The Company’s medical cost trend rate assumption as of December 31, 2004 is 9.0% and is expected to gradually decrease to 5.0% in later years.

Accounting for regulated operations

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

Management evaluates whether or not recovery of its regulatory assets through future regulated rates is probable and makes various assumptions in its analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If recovery of regulatory assets is determined to be less than probable, the regulatory asset will be written off and an expense will be recorded in the period such assessment is made. Management currently believes the recovery of its regulatory assets is probable. See Notes 2 and 12 to the Consolidated Financial Statements.

Accounting for gas and oil operations

The Company follows the full cost method of accounting for gas and oil exploration and production activities prescribed by the Securities and Exchange Commission (SEC). Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized and subsequently depreciated using the units-of-production method. The depreciable base of costs includes estimated future costs to be incurred in developing proved gas and oil reserves, as well as capitalized asset retirement costs, net of projected salvage values. Capitalized costs in the depreciable base are subject to a ceiling test prescribed by the SEC. The test limits capitalized amounts to a ceiling—the present value of estimated future net revenues to be derived from the production of proved gas and oil reserves assuming period-end pricing adjusted for cash flow hedges in place. The Company performs the ceiling test quarterly and would recognize asset impairments to the extent that total capitalized costs exceed the ceiling. In addition, gains or losses on the sale or other disposition of gas and oil properties are not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of natural gas and oil.

The Company’s estimate of proved reserves requires a large degree of judgment and is dependent on factors such as historical data, engineering estimates of proved reserve quantities, estimates of the amount and timing of future expenditures to develop the proved reserves, and estimates of future production from the proved reserves. Given the volatility of natural gas and oil prices, it is possible that the Company’s estimate of discounted future net cash flows from proved natural gas and oil reserves that is used to calculate the ceiling could change in the near term.

The process to estimate reserves is imprecise, and estimates are subject to revision. In the last five years, revisions to the Company’s estimates of proved developed and undeveloped reserves have averaged approximately 4% of the previous year’s estimate. If there is a significant variance in any of the Company’s estimates or assumptions in the future and revisions to the value of the Company’s proved reserves are necessary, related depletion expense and the calculation of the ceiling test would be affected and recognition of natural gas and oil property impairments could occur. See Notes 2 and 25 to the Consolidated Financial Statements.

Income Taxes

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

Newly Adopted Accounting Standards

During 2004 and 2003, the Company was required to adopt several new accounting standards, the requirements of which are discussed in Notes 2 and 3 to the Consolidated Financial Statements. The adoption of Financial Accounting Standards Board (FASB) Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, (FIN 46R) on December 31, 2003 with respect to special purpose entities, affected the

2004 / Page 12

2004 / Page 13

comparability of the Company’s 2004 Consolidated Statement of Income to prior years as follows:

•

The Company was required to consolidate a variable interest lessor entity through which the Company had financed and leased a new power generation project. As a result, the Consolidated Balance Sheet as of December 31, 2003 reflects an additional $223 million in net property, plant and equipment and deferred charges and $234 million of related debt. In 2004, the Company’s Consolidated Statement of Income reflects depreciation expense on the net property, plant and equipment and interest expense on the debt associated with this entity, whereas in prior years it reflected as rent expense in other operations and maintenance expense, the lease payments to the entity.

•

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

Other

The Company enters into buy/sell and related agreements as a means to reposition its offshore Gulf of Mexico crude oil production to more liquid marketing locations onshore. The Company typically enters into either a single or a series of buy/sell transactions in which it sells its crude oil production at the offshore field delivery point and buys similar quantities at Cushing, Oklahoma for sale to third parties. The Company is able to enhance profitability by selling to a wide array of refiners and/or trading companies at Cushing, one of the largest crude oil markets in the world, versus restricting sales to a limited number of refinery purchasers in the Gulf of Mexico. These transactions require physical delivery of the crude oil and the risks and rewards of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling and counter party nonperformance risk.

Under the primary guidance of Emerging Issue Task Force (EITF) Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent, the Company presents the sales and purchases related to its crude oil buy/sell arrangements on a gross basis in its Consolidated Statements of Income. The EITF is currently discussing Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, which specifically focuses on purchase and sale transactions made pursuant to crude oil buy/sell arrangements. The EITF is evaluating whether these types of transactions should be presented net in the Consolidated Statements of Income. While resolution of this issue may affect the income statement presentation of these revenues and expenses, there would be no impact on the Company’s results of operations or cash flows. The portion of the Company’s operating revenue from external customers related to buy/sell activity for the years 2004, 2003, and 2002 was 5.3%, 3.9%, and 4.4% respectively. Reported production volumes are not impacted, as only the initial sale of Company owned production is included in reported production volumes. It is estimated that approximately 62% of the Company’s 2004 oil production was marketed through the use of one or more crude oil buy/sell agreements. See Note 2 to the Consolidated Financial Statements.

Results of Operations

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


	Year Ended December 31,
	2004			2003
(millions)
Energy	$	228		$	213
Delivery		184			177
Exploration & Production		520			317
Primary operating segments		932			707
Corporate and Other		(65	)		(69	)
Consolidated	$	867		$	638

Overview

2004 vs. 2003

Net income increased 36% to $867 million as compared to 2003. The Company’s primary operating segments contributed an additional $225 million to net income. See Note 23 to the Consolidated Financial Statements for more information about the Company’s operating segments. This increase largely reflects:

•

A higher contribution from the energy operations reflecting higher gas prices at producer services and higher gas margins from transportation, storage and extraction activities and sales of by-products;

•

A higher contribution from nonregulated retail energy marketing operations, primarily reflecting an increase in average customer accounts and higher electric and gas margins; and

•

A higher contribution from exploration and production operations due to favorable changes in the fair value of certain oil options, higher average realized prices for gas and the recognition of business interruption insurance revenue associated with the recovery of delayed gas and oil production due to Hurricane Ivan. Results were also affected by the recognition of revenue in connection with deliveries under volumetric production payment (VPP) agreements, partially offset by lower gas production, reflecting the sale of mineral rights under the VPP agreements.

Analysis of Consolidated Operations

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


	Year Ended December 31,
	2004		2003
(millions)
Operating Revenue
Regulated gas sales	$	1,422	$	1,259
Nonregulated electric sales⁽¹⁾		390		232
Nonregulated gas sales⁽¹⁾		1,996		1,531
Gas transportation and storage⁽¹⁾		819		767
Gas and oil production		1,297		1,177
Other⁽¹⁾		640		347
Operating Expenses
Purchased gas, net⁽¹⁾		2,810		2,206
Electric fuel and energy purchases, net⁽¹⁾		349		196
Liquids, pipeline capacity and other purchases		292		187
Other operations and maintenance⁽¹⁾		750		712
Depreciation, depletion and amortization		627		581
Other taxes		270		225
Other income (loss)		55		(32	)
Interest and related charges⁽¹⁾		172		153
Income taxes		482		372
Cumulative effect of changes in accounting principles (net of income taxes of $8)		—		(11	)

(1)

Includes transactions with other Dominion subsidiaries related to Dominion’s enterprise-wide price risk management and other activities. See Note 22 to the Consolidated Financial Statements for a description of transactions with affiliates.

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

Operating Revenue

Regulated gas sales revenue increased 13% to $1.4 billion, largely resulting from a $198 million increase due to higher rates for regulated gas distribution operations primarily related to the recovery of higher gas prices and a $20 million increase resulting from the return of customers from Energy Choice programs, partially offset by an $87 million decrease associated with milder weather and lower industrial sales. The effect of this net increase in regulated gas sales revenue was largely offset by a comparable increase in Purchased gas, net expense.

Nonregulated electric sales revenue increased 68% to $390 million, resulting primarily from increased volumes ($165 million) and higher prices ($16 million) in the Company’s nonregulated retail energy marketing operations, partially offset by lower revenue ($19 million) due to the sale of CNGI’s generation assets in Hawaii in December 2003.

Nonregulated gas sales revenue increased 30% to $2.0 billion, which was largely offset by a corresponding increase in Purchased gas, net expense. This increase primarily reflects:

•

A $279 million increase in revenue from producer services operations, driven by higher prices ($157 million) and higher volumes ($122 million);

•

A $131 million increase in revenue from nonregulated retail energy marketing operations, reflecting higher prices ($76 million) and higher volumes ($55 million); and

•

A $61 million increase in revenue from sales of gas purchased by exploration and production operations to facilitate gas transportation and satisfy other agreements.

Gas transportation and storage revenue increased 7% to $819 million, primarily reflecting:

•

A $29 million increase due to the August 2003 reactivation of the Cove Point LNG facility, which was acquired by the Company in September 2002; and

•

A $27 million increase in revenue from gas transmission operations primarily reflecting increased transportation, storage, gathering and extraction revenues.

Gas and oil production revenue increased 10% to $1.3 billion as a result of:

•

A $26 million increase in revenue from oil production, largely reflecting higher volumes related to the Gulf of Mexico Devils Tower project; and

•

A $180 million increase in revenue recognized related to deliveries under VPP transactions; partially offset by

•

A $75 million decrease in revenue from gas production, primarily reflecting the sale of mineral rights under the VPP agreements.

Other revenue increased 84% to $640 million, primarily reflecting:

•

A $71 million increase in sales of extracted products principally due to increased volumes;

•

A $109 million increase in revenue from sales of purchased oil by exploration and production operations. These increases in other revenue were largely offset by corresponding increases in Liquids, pipeline capacity and other purchases expense; and

2004 / Page 14

•

A $100 million increase due to the recognition of business interruption insurance revenue associated with the recovery of delayed gas and oil production due to Hurricane Ivan.

Operating Expenses and Other Items

Purchased gas, net expense increased 27% to $2.8 billion, principally resulting from:

•

A $274 million increase associated with producer services operations, reflecting higher prices ($159 million) and increased volumes ($115 million), as discussed above in Nonregulated gas sales revenue;

•

A $130 million increase associated with regulated gas sales discussed above in Regulated gas sales revenue;

•

An $83 million increase associated with nonregulated retail energy marketing operations, reflecting increased volumes ($56 million) and higher prices ($27 million);

•

A $66 million increase from gas transmission operations due to increased gathering and extraction activities and higher gas usage; and

•

A $58 million increase related to purchases of gas by exploration and production operations to facilitate gas transportation and satisfy other agreements, as discussed above in Nonregulated gas sales revenue.

Electric fuel and energy purchases expense increased 78% to $349 million, primarily reflecting the following:

•

A $162 million increase related to nonregulated retail energy marketing operations reflecting increased volumes ($153 million) and higher prices ($9 million); partially offset by

•

A $13 million decrease related to the sale of CNGI’s Hawaii generation facility in December 2003.

Liquids, pipeline capacity and other purchases expense increased 56% to $292 million, reflecting primarily a $108 million increase related to purchases of oil by exploration and production operations, as discussed above in Other revenue.

Other operations and maintenance expense increased 5% to $750 million, primarily reflecting the following:

•

A $96 million charge from the discontinuance of hedge accounting for certain oil hedges, resulting from an interruption of oil production in the Gulf of Mexico caused by Hurricane Ivan, and subsequent changes in the fair value of those hedges during the third quarter;

•

A $39 million increase in costs related to gas and oil production activities;

•

A $22 million increase resulting from lower pension credits; and

•

A $16 million increase in bad debt expense; partially offset by

•

A $117 million net benefit due to favorable changes in the fair value of certain oil options related to exploration and production operations. During 2004, the Company effectively settled certain oil options not designated as hedges by entering into offsetting option positions that had the effect of preserving approximately $119 million in mark-to-market gains attributable to favorable changes in time value; and

•

A $16 million asset impairment charge recognized in 2003 related to the Company’s generation facility in Hawaii that was sold in December 2003. No comparable charge was recognized during 2004.

Depreciation, depletion and amortization (DD&A) expense increased 8% to $627 million, primarily reflecting higher exploration and production finding and development costs, and higher depreciation expense resulting from property additions, including the consolidation of a variable interest entity as a result of adopting FIN 46R at December 31, 2003.

Other taxes increased 20% to $270 million, primarily due to higher gross receipts taxes and higher severance and property taxes associated with increased commodity prices.

Other income increased $87 million, primarily reflecting a $31 million benefit in 2004 related to the sale of a portion of CNGI’s equity investment in an Australian pipeline business, consisting of an $18 million favorable adjustment to the carrying amount of this investment and a $13 million gain on the sale. In 2003, a $62 million impairment charge was recognized on this investment, based on estimated fair value at that time.

Interest expense increased 12% to $172 million, primarily reflecting:

•

A reduction in the amount of interest capitalized ($11 million), primarily related to unproved gas and oil properties; and

•

The consolidation of debt related to a special purpose lessor entity as a result of the adoption of FIN 46R on December 31, 2003 ($4 million). In prior years, this expense was recorded in other operations and maintenance expense.

Income taxes—The Company’s effective tax rate decreased 0.7% to 35.8% for 2004, reflecting a net reduction in state tax expense partially offset by other factors.

Cumulative effect of changes in accounting principles—During 2003, the Company was required to adopt several new accounting standards, resulting in a net after-tax loss of $11 million which included the following:

•

A $5 million after-tax loss related to Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, and

•

A $6 million after-tax loss related to FIN 46R.

Segment Results of Operations

Energy Segment

Energy includes the Company’s natural gas transmission pipeline and storage system, certain gas production operations, an LNG import and storage facility and producer services operations which include aggregation of gas supply and related wholesale activities.


	2004		2003
(millions)
Net income contribution	$	228	$	213
Gas sales (bcf)		234		213
Gas transportation throughput (bcf)		704		614

bcf = billion cubic feet

2004 / Page 15

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


2004 vs. 2003	Increase (Decrease)
(millions)
Gas prices	$	4
Gas transmission operations		11
Change in net income contribution	$	15

Energy’s net income contribution increased $15 million, primarily reflecting:

•

Higher gas prices on producer services operations; and

•

Higher gas margins from transportation, storage and extraction activities and sales of by-products partially offset by higher operating expenses.

Delivery Segment

Delivery includes the Company’s regulated gas distribution and customer service business, as well as nonregulated energy marketing operations and related products and services.


	2004		2003
(millions)
Net income contribution	$	184	$	177
Throughput (bcf):
Gas sales		127		134
Gas transportation		244		239
Total throughput		371		373

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


2004 vs. 2003	Increase (Decrease)
(millions)
Weather	$	(9	)
Nonregulated retail energy marketing operations		31
Pension expense		(9	)
Other taxes		(8	)
Other		2
Change in net income contribution	$	7

Delivery’s net income contribution increased $7 million, primarily reflecting:

•

A decrease in regulated gas sales due to comparably warmer weather in the first quarter and fourth quarter of 2004. Heating degree-days were 5% lower in the franchise service areas as compared to 2003;

•

A higher contribution from nonregulated retail energy marketing operations, primarily reflecting an increase in average customer accounts and higher electric and gas margins;

•

A decrease in net pension credits; and

•

An increase in other taxes related to regulated gas operations due to favorable adjustments made in 2003 with no comparable items in 2004.

Exploration & Production Segment

Exploration & Production includes the Company’s gas and oil exploration, development and production business.


	2004		2003
(millions)
Net income contribution	$	520	$	317
Gas production (bcf)		266		280
Oil production (million bbls)		9		8
Average realized prices with hedging results:
Gas (per mcf)⁽¹⁾	$	4.13	$	4.11
Oil (per bbl)		24.49		24.79
Average prices without hedging results:
Gas (per mcf)⁽¹⁾		5.83		5.23
Oil (per bbl)		39.96		30.73
Other Information:
DD&A (per mcfe)	$	1.40	$	1.30
Average production (lifting) cost (per mcfe)		.78		.75

bbl = barrel

mcf = thousand cubic feet

mcfe = thousand cubic feet equivalent

(1)

Excludes $223 million and $43 million of revenue recognized in 2004 and 2003, respectively, under the VPP agreements described in Note 10 to the Consolidated Financial Statements.

Presented below, on an after-tax basis, are the key factors impacting the Exploration & Production’s operating results:


2004 vs. 2003	Increase (Decrease)
(millions)
VPP revenue	$	114
Business interruption insurance		61
Gas and oil—production		(25	)
Gas and oil—prices		10
Operations and maintenance		43
DD&A—rate		(22	)
DD&A—production		6
Income taxes		20
Other		(4	)
Change in net income contribution	$	203

Exploration & Production’s net income contribution increased $203 million, primarily reflecting:

•

Recognition of revenue in connection with deliveries under the VPP agreements;

•

The recognition of business interruption insurance revenue associated with the recovery of delayed gas and oil production due to Hurricane Ivan;

•

Lower gas production reflecting the sale of mineral rights under the VPP agreements;

•

Higher oil production reflecting production related to the deepwater Gulf of Mexico Devils Tower project;

•

Lower operations and maintenance expenses, primarily due to favorable changes in the fair value of certain oil options, partially offset by an increase in production costs;

•

A higher rate for depreciation, depletion and amortization, primarily reflecting higher industry finding and development costs, increased acquisition costs and the effect of the reduction in reserves attributable to the VPP transactions; and

2004 / Page 16

•

Lower state income taxes as a result of a lower combined effective state tax rate. The state tax rates are impacted by changes in state income tax laws, the corporate investment profile in numerous states and the volume of business transactions.

Corporate and Other

Corporate and Other includes the Company’s corporate and other functions, including the activities of CNGI, the Company’s power generating facility and other minor subsidiaries.

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


	2004			2003
(millions)
Net expense	$	(65	)	$	(69	)

Corporate and Other reported net expenses of $65 million for 2004, compared to net expenses of $69 million in 2003.

The net expenses in 2004 primarily reflected the following:

•

$96 million of losses recorded in other operations and maintenance expense ($61 million after-tax) related to the discontinuance of hedge accounting for certain oil hedges, resulting from an interruption in oil production caused by Hurricane Ivan, and subsequent changes in the fair value of those hedges during the third quarter, attributable to the Exploration & Production segment; and

•

An additional $31 million tax valuation allowance related to certain CNGI investments that were held for sale; partially offset by

•

A $31 million benefit in 2004 related to the sale of a portion of CNGI’s equity investment in an Australian pipeline business, consisting of an $18 million favorable adjustment to the carrying amount of this investment and a $13 million gain on the sale.

The 2003 results primarily reflect impairment losses totaling $78 million ($65 million after-tax) related to investments in the Australian pipeline business and a generation facility in Hawaii that was sold in December 2003. In addition, the following specific items attributable to operating segments contributed to the 2003 results:

•

A $5 million after-tax loss associated with the cumulative effect of a change in accounting principle related to the adoption of SFAS No. 143 on January 1, 2003 attributable to the Energy segment (See Note 3 to the Consolidated Financial Statements);

•

A $6 million after-tax loss associated with the cumulative effect of a change in accounting principle related to the adoption of FIN 46R on December 31, 2003 (see Note 3 to the Consolidated Financial Statements); and

•

A $6 million ($4 million after-tax) charge for severance costs related to workforce reductions recorded in other operations and maintenance expense, including $3 million, $2 million and $1 million attributable to the Energy, Delivery and Exploration & Production segments, respectively.

Credit Risk

The Company’s exposure to potential credit risk results primarily from its marketing of natural gas and sales of gas and oil production. Presented below is a summary of the Company’s net credit exposure as of December 31, 2004. The Company calculates its gross credit exposure for each counterparty as the unrealized fair value of derivative contracts plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral. At December 31, 2004, the Company held no collateral made available by its counterparties.


	Gross Credit Exposure
(millions)
Investment grade⁽¹⁾	$	232
Non-investment grade⁽²⁾		32
No external ratings:
Internally rated—investment grade⁽³⁾		42
Internally rated—non-investment grade⁽⁴⁾		98
Total	$	404

(1)

Designations as investment grade are based upon minimum credit ratings assigned by Moody’s Investors Service (Moody’s) and Standard & Poor’s Rating Group, a division of the McGraw-Hill Companies, Inc. (Standard & Poor’s). The five largest counterparty exposures, combined, for this category represented approximately 18% of the total gross credit exposure.

(2)

The five largest counterparty exposures, combined, for this category represented approximately 6% of the total gross credit exposure.

(3)

The five largest counterparty exposures, combined, for this category represented approximately 5% of the total gross credit exposure.

(4)

The five largest counterparty exposures, combined, for this category represented approximately 6% of the total gross credit exposure.

Risk Factors and Cautionary Statements That May Affect Future Results

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

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

2004 / Page 17

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

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

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

In addition, the Company uses financial derivatives to hedge future sales of its gas and oil production. These hedge arrangements generally include margin requirements that requires the Company to deposit funds or post letters of credit with counterparties to cover the fair value of covered contracts in excess of agreed upon credit limits. When commodity prices rise to levels substantially higher than the levels where it has hedged future sales, the Company may be required to use a material portion of its available liquidity to cover these margin requirements. In some circumstances, this could have a compounding effect on the Company’s financial liquidity and results.

For additional information concerning derivatives and commodity-based trading contracts, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk, Market Rate Sensitive Instruments and Risk Management and Notes 2 and 9 to the Consolidated Financial Statements.

The Company’s exploration and production business is dependent on factors that cannot be predicted or controlled and that could damage facilities, disrupt production or reduce the book value of its assets. Factors that may affect the Company’s financial results include weather that damages or causes the shutdown of its gas and oil producing facilities, fluctuations in natural gas and crude oil prices, results of future drilling and well completion activities and the Company’s ability to acquire additional land positions in competitive lease areas, as well as inherent operational risks that could disrupt production.

Short-term market declines in the prices of natural gas and oil could adversely affect the Company’s financial results by causing a permanent write-down of its natural gas and oil properties as required by the full cost method of accounting. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. If net capitalized costs exceed the present value of estimated future net revenues based on hedge-adjusted period-end prices from the production of proved gas and oil reserves (the ceiling test) at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period.

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

Changing rating agency requirements could negatively affect the Company’s growth and business strategy. As of February 1, 2005, the Company’s senior unsecured debt is rated BBB+, negative outlook, by Standard & Poor’s and A3, negative outlook, by Moody’s. Both agencies have implemented more stringent applications of the financial requirements for various ratings levels. In order to maintain its current credit ratings in light of these or future new requirements, the Company may find it necessary to take steps or change its business plans in ways that may adversely affect its growth and earnings. A reduction in the Company’s credit ratings by either Standard & Poor’s or Moody’s could increase its borrowing costs and adversely affect operating results and could require it to post additional margin in connection with some of its marketing activities.

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

2004 / Page 18

2004 / Page 19

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

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

Market Rate Sensitive Instruments and Risk Management

The Company’s financial instruments, commodity contracts and related derivative instruments are exposed to potential losses due to adverse changes in interest rates and commodity prices as described below. Interest rate risk generally is related to the Company’s outstanding debt. Commodity price risk is present in the Company’s gas and oil production and procurement operations and energy marketing operations due to the exposure to market shifts in prices received and paid for natural gas and oil. The Company uses derivative instruments to manage price risk exposures for these operations.

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

Commodity Price Risk

The Company manages the price risk associated with purchases and sales of natural gas and oil by using derivative commodity instruments, including futures, forwards, options and swaps. For sensitivity analysis purposes, the fair value of the Company’s derivative commodity instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Market prices and volatility are principally determined based on quoted prices on the futures exchange. A hypothetical 10% unfavorable change in market prices of the Company’s commodity-based financial derivative instruments would have resulted in a decrease in fair value of approximately $454 million and $370 million as of December 31, 2004 and 2003, respectively.

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

Interest Rate Risk

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

Investment Price Risk

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

Risk Management Policies

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

Item 8. Financial Statements and Supplementary Data

Index


		Page No.
Report of Management‘s Responsibilities		21

Report of Independent Registered Public Accounting Firm		22

Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002		23

Consolidated Balance Sheets at December 31, 2004 and 2003		24

Consolidated Statements of Common Shareholder’s Equity and Comprehensive Income at December 31, 2004, 2003 and 2002 and for the years then ended		26

Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002		27

Notes to Consolidated Financial Statements		28

2004 / Page 20

Report of Management’s Responsibilities

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

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

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

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

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

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

2004 / Page 21

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Consolidated Natural Gas Company

Richmond, Virginia

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

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

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

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

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 28, 2005

2004 / Page 22

Consolidated Natural Gas Company

Consolidated Statements of Income


Year Ended December 31,	2004		2003			2002
(millions)
Operating Revenue
External customers	$	5,472	$	4,597		$	3,724
Affiliated customers		1,092		716			176
Total operating revenue		6,564		5,313			3,900
Operating Expenses
Purchased gas, net:
External suppliers		2,283		1,593			977
Affiliated suppliers		527		613			270
Electric fuel and energy purchases, net:
External suppliers		153		116			66
Affiliated suppliers		196		80			37
Liquids, pipeline capacity and other purchases		292		187			156
Other operations and maintenance:
External suppliers		587		554			408
Affiliated suppliers		163		158			160
Depreciation, depletion and amortization		627		581			554
Other taxes		270		225			202
Total operating expenses		5,098		4,107			2,830
Income from operations		1,466		1,206			1,070
Other income (loss)		55		(32	)		35
Interest and related charges:
Interest expense, net		156		137			136
Interest expense—junior subordinated notes payable to affiliated trust		16		—			—
Distributions—mandatorily redeemable trust preferred securities		—		16			19
Total interest and related charges		172		153			155
Income before income taxes		1,349		1,021			950
Income taxes		482		372			312
Income before cumulative effect of changes in accounting principles		867		649			638
Cumulative effect of changes in accounting principles (net of income taxes of $8)		—		(11	)		—
Net Income	$	867	$	638		$	638

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

2004 / Page 23

Consolidated Natural Gas Company

Consolidated Balance Sheets


At December 31,	2004			2003
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	19		$	39
Accounts receivable:
Customers (less allowance for doubtful accounts of $28 in 2004 and $37 in 2003)		1,044			795
Other		61			45
Receivables due from affiliates		125			340
Inventories:
Materials and supplies		32			41
Gas stored		190			197
Derivative assets		504			106
Deferred income taxes		280			122
Prepayments		57			56
Other		317			296
Total current assets		2,629			2,037
Investments
Investments in affiliates		204			203
Other		87			79
Total investments		291			282
Property, Plant and Equipment
Property, plant and equipment		17,220			15,854
Accumulated depreciation, depletion and amortization		(6,170	)		(5,674	)
Total property, plant and equipment, net		11,050			10,180
Deferred Charges and Other Assets
Goodwill, net		623			626
Regulatory assets		369			328
Prepaid pension cost		984			872
Derivative assets		541			84
Other		235			210
Total deferred charges and other assets		2,752			2,120
Total assets	$	16,722		$	14,619

2004 / Page 24


At December 31,	2004			2003
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	150		$	501
Short-term debt		—			151
Accounts payable, trade		949			655
Payables to affiliates		111			118
Affiliated current borrowings		1,195			1,027
Accrued interest, payroll and taxes		229			214
Derivative liabilities		1,237			620
Other		341			258
Total current liabilities		4,212			3,544
Long-Term Debt
Long-term debt		3,454			3,213
Junior subordinated notes payable to affiliated trust		206			206
Total long-term debt		3,660			3,419
Deferred Credits and Other Liabilities
Deferred income taxes		2,310			1,890
Deferred investment tax credits		11			12
Derivative liabilities		1,234			669
Regulatory liabilities		223			212
Other		592			508
Total deferred credits and other liabilities		4,370			3,291
Total liabilities		12,242			10,254
Commitments and Contingencies (see Note 19)
Common Shareholder’s Equity
Common stock, no par value, 100 shares authorized and outstanding		1,816			1,816
Other paid-in capital		2,520			2,478
Retained earnings		993			608
Accumulated other comprehensive loss		(849	)		(537	)
Total common shareholder’s equity		4,480			4,365
Total liabilities and shareholder’s equity	$	16,722		$	14,619

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

2004 / Page 25

Consolidated Natural Gas Company

Consolidated Statements of Common Shareholder’s Equity and Comprehensive Income


	Common Stock
	Shares	Amount		Other Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
(millions, except shares)
Balance at December 31, 2001	100	$	1,816	$	936	$	166		$	82		$	3,000
Comprehensive income:
Net income							638						638
Unrealized losses on investment securities, net of tax benefit of $0.5										(1	)		(1	)
Net deferred losses on derivatives—hedging activities, net of tax benefit of $194										(382	)		(382	)
Minimum pension liability adjustment, net of tax expense of $0.5										1			1
Amount reclassified to net income:
Net losses on derivatives—hedging activities, net of tax benefit of $0.5										2			2
Total comprehensive income							638			(380	)		258
Equity contribution by parent					932								932
Tax benefit from stock awards and stock options exercised					3								3
Dividends							(384	)					(384	)
Balance at December 31, 2002	100		1,816		1,871		420			(298	)		3,809
Comprehensive income:
Net income							638						638
Unrealized gains on investment securities, net of tax expense of $0.5										1			1
Foreign currency translation adjustment										33			33
Net deferred losses on derivatives—hedging activities, net of tax benefit of $291										(501	)		(501	)
Amount reclassified to net income:
Net losses on derivatives—hedging activities, net of tax benefit of $131										228			228
Total comprehensive income							638			(239	)		399
Equity contribution by parent					606								606
Tax benefit from stock awards and stock options exercised					1								1
Dividends							(450	)					(450	)
Balance at December 31, 2003	100		1,816		2,478		608			(537	)		4,365
Comprehensive income:
Net income							867						867
Foreign currency translation adjustment										11			11
Net deferred losses on derivatives—hedging activities, net of tax benefit of $431										(744	)		(744	)
Amounts reclassified to net income:
Net losses on derivatives—hedging activities, net of tax benefit of $269										465			465
Foreign currency translation adjustment⁽¹⁾										(44	)		(44	)
Total comprehensive income							867			(312	)		555
Equity contribution by parent					41								41
Tax benefit from stock awards and stock options exercised					1								1
Dividends							(482	)					(482	)
Balance at December 31, 2004	100	$	1,816	$	2,520	$	993		$	(849	)	$	4,480

(1)

Reclassified to earnings due to the sale of CNG International investments.

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

2004 / Page 26

Consolidated Natural Gas Company

Consolidated Statements of Cash Flows


Year Ended December 31,	2004			2003			2002
(millions)
Operating Activities
Net income	$	867		$	638		$	638
Adjustments to reconcile net income to net cash from operating activities:
Impairment (recovery) of CNG International assets		(18	)		78			—
Depreciation, depletion and amortization		627			581			554
Deferred income taxes and investment tax credits, net		398			239			393
Other adjustments for non-cash items		16			(50	)		15
Changes in :
Accounts receivable		(265	)		(153	)		(62	)
Receivables due from affiliates		215			(244	)		(1	)
Inventories		16			(123	)		33
Deferred purchased gas costs, net		2			(41	)		(125	)
Margin deposit assets and liabilities		(29	)		(7	)		(120	)
Prepaid pension cost		(112	)		(134	)		(170	)
Accounts payable, trade		294			54			19
Payables to affiliates		(7	)		16			(154	)
Accrued interest, payroll and taxes		57			28			8
Deferred revenue		(223	)		(43	)		—
Other operating assets and liabilities		(220	)		76			108
Net cash provided by operating activities		1,618			915			1,136
Investing Activities
Plant construction and other property additions:
Additions to gas and oil properties, including acquisitions		(1,168	)		(1,166	)		(1,336	)
Other		(378	)		(378	)		(349	)
Proceeds from sales of gas and oil properties		413			291			—
Acquisition of Cove Point, net of cash acquired		—			—			(225	)
Other		47			(67	)		55
Net cash used in investing activities		(1,086	)		(1,320	)		(1,855	)
Financing Activities
Issuance of long-term debt		400			200			—
Repayment of long-term debt		(489	)		(151	)		(6	)
Short-term borrowings from affiliates, net		168			1,065			1,463
Repayment of short-term debt, net		(151	)		(246	)		(379	)
Dividends paid		(482	)		(450	)		(384	)
Other		2			4			(6	)
Net cash provided by (used in) financing activities		(552	)		422			688
Increase (decrease) in cash and cash equivalents		(20	)		17			(31	)
Cash and cash equivalents at beginning of the year		39			22			53
Cash and cash equivalents at end of the year	$	19		$	39		$	22
Supplemental Cash Flow Information
Net cash paid (received) during the year for:
Interest and related charges, excluding capitalized amounts	$	191		$	178		$	138
Income taxes		14			80			(62	)
Noncash transaction from financing activities:
Conversion of short-term borrowings and other amounts payable to parent to other paid-in capital		41			606			932

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

2004 / Page 27

Consolidated Natural Gas Company

Notes to Consolidated Financial Statements

Note 1. Nature of Operations

Consolidated Natural Gas Company (the Company), a public utility holding company registered under the Public Utility Holding Company Act of 1935 (1935 Act), is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion). The Company, through its subsidiaries, operates in all phases of the natural gas business, explores for and produces gas and oil and provides a variety of energy marketing services. Its regulated gas distribution subsidiaries serve approximately 1.7 million residential, commercial and industrial gas sales and transportation customer accounts in Ohio, Pennsylvania and West Virginia and its nonregulated retail energy marketing businesses serve approximately 1.2 million residential and commercial gas and electric customer accounts in the Northeast, Mid-Atlantic and Midwest. The Company operates an interstate gas transmission pipeline system in the Midwest, the Mid-Atlantic states and the Northeast and a liquefied natural gas (LNG) import and storage facility in Maryland. The Company’s producer services operations involve the aggregation of natural gas supply and related wholesale activities. The Company’s exploration and production operations are located in several major gas and oil producing basins in the United States, both onshore and offshore.

The Company manages its daily operations through three primary operating segments: Energy, Delivery and Exploration & Production. In addition, the Company reports its corporate and other functions as a segment. Assets remain wholly-owned by the Company’s legal subsidiaries.

The Energy segment includes Dominion Transmission, Inc. (DTI), Dominion Cove Point, Inc. (DCP) and Dominion Field Services, Inc. (DFS). DTI operates a regional interstate pipeline and storage system and is regulated by the Federal Energy Regulatory Commission (FERC). DCP operates an LNG import and storage facility and is regulated by FERC. DFS is engaged in the aggregation of metered gas supplies and other related wholesale activities.

The Delivery segment includes the Company’s regulated gas distribution subsidiaries, The East Ohio Gas Company, The Peoples Natural Gas Company and Hope Gas, Inc., as well as the nonregulated marketing subsidiaries, Dominion Retail, Inc. (Dominion Retail) and Dominion Products and Services, Inc. The regulated gas distribution subsidiaries are subject to price regulation by their respective state utility commissions. Dominion Retail pursues opportunities arising from the deregulation of the energy industry at the retail level.

The Exploration & Production segment includes Dominion Exploration & Production, Inc. and Dominion Oklahoma Texas Exploration & Production, Inc. These subsidiaries explore for and produce gas and oil.

The “Company” is used throughout this report and, depending on the context of its use, may represent any of the following: the legal entity, Consolidated Natural Gas Company, one of Consolidated Natural Gas Company’s consolidated subsidiaries or the entirety of Consolidated Natural Gas Company and its consolidated subsidiaries.

Note 2. Significant Accounting Policies

General

The Company makes certain estimates and assumptions in preparing its Consolidated Financial Statements in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles). These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses for the periods presented. Actual results may differ from those estimates.

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

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

Operating Revenue

Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. The Company’s customer accounts receivable at December 31, 2004 and 2003 included $133 million and $108 million, respectively, of accrued unbilled revenue based on estimated amounts of natural gas delivered but not yet billed to its utility customers. The Company estimates unbilled utility revenue based on weather factors, historical usage and applicable customer rates.

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

•

Regulated gas sales consist primarily of state-regulated retail natural gas sales and related distribution services;

•

Nonregulated electric sales consist primarily of sales of electricity to residential and commercial customers at contracted fixed prices and market-based rates;

•

Nonregulated gas sales consist primarily of sales of natural gas at market-based rates, sales of gas purchased from third parties and other gas marketing activities;

•

Gas transportation and storage consists primarily of regulated sales of gathering, transmission, distribution and storage services. Also included are regulated gas distribution charges to retail distribution service customers opting for alternate suppliers;

•

Gas and oil production consists primarily of sales of natural gas, oil and condensate produced by the Company, including the recognition of revenue previously deferred in connection with the volumetric production payment (VPP) transactions described in Note 10. Gas and oil production revenue is reported net of royalties; and

•

Other revenue consists primarily of miscellaneous service revenue from gas distribution operations; sales of extracted

2004 / Page 28

Notes to Consolidated Financial Statements, Continued

products; gas and oil processing; gas transmission pipeline capacity release; business interruption insurance revenue associated with delayed gas and oil production caused by Hurricane Ivan; and sales activity related to agreements used to facilitate the marketing of oil production.

Crude Oil Buy/Sell Arrangements

Under the primary guidance of Emerging Issue Task Force (EITF) Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent, the Company presents the sales and purchases related to its crude oil buy/sell arrangements on a gross basis in its Consolidated Statements of Income. The EITF is currently discussing Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, which specifically focuses on purchase and sale transactions made pursuant to crude oil buy/sell arrangements. The EITF is evaluating whether these types of transactions should be presented net in the Consolidated Statements of Income. While resolution of this issue may affect the income statement presentation of these revenues and expenses, there would be no impact on the Company’s results of operations or cash flows. Amounts currently shown on a gross basis in the Company’s Consolidated Statements of Income that could be impacted by further EITF deliberations in this area are summarized below.


	Year Ended December 31,
	2004		2003		2002
(millions)
Sale activity included in operating revenue	$	290	$	181	$	164
Purchase activity included in operating expenses⁽¹⁾		271		163		147

(1) Included in liquids, pipeline capacity and other purchases

Purchased Gas—Deferred Costs

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

Income Taxes

The Company files a consolidated federal income tax return and participates in an intercompany tax allocation agreement with Dominion and its subsidiaries. The Company’s current income taxes are based on its taxable income, determined on a separate company basis. At December 31, 2004 and 2003, the Company’s Consolidated Balance Sheets include $23 million and $8 million, respectively, of current taxes payable to Dominion (recorded in accrued interest, payroll and taxes). However, under the 1935 Act and the intercompany tax allocation agreement, the Company’s cash payments to Dominion are limited. Where permitted by regulatory authorities, the treatment of temporary differences can differ from the requirements of Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes. Accordingly, a regulatory asset has been recognized if it is probable that future revenue will be provided for the payment of deferred tax liabilities. Deferred investment tax credits are being amortized over the service lives of the property giving rise to such credits. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized.

Cash and Cash Equivalents

Current banking arrangements generally do not require checks to be funded until actually presented for payment. At December 31, 2004 and 2003, accounts payable includes $67 million and $45 million, respectively of checks outstanding but not yet presented for payment. For purposes of the Consolidated Statements of Cash Flows, the Company considers cash and cash equivalents to include cash on hand, cash in banks and temporary investments purchased with a remaining maturity of three months or less.

Inventories

Materials and supplies inventories are valued primarily using the weighted-average cost method. Stored gas inventory used in local gas distribution operations is valued using the last-in-first-out (LIFO) method. Under the LIFO method, those inventories were valued at $59 million at both December 31, 2004 and 2003. Based on the average price of gas purchased during 2004, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by approximately $302 million. Stored gas inventory held by certain nonregulated gas operations is valued using the weighted-average cost method.

Derivative Instruments

The Company uses derivative instruments such as futures, swaps, forwards and options to manage the commodity and financial market risks of its business operations.

All derivatives, except those for which an exception applies, are reported on the Consolidated Balance Sheets at fair value. One of the exceptions—normal purchases and normal sales—may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenue resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance. Derivative contracts that are subject to fair value accounting, including unrealized gain positions and purchased options, are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as

2004 / Page 29

Notes to Consolidated Financial Statements, Continued

derivative liabilities. For derivatives that are not designated as hedging instruments, any changes in fair value are recorded in earnings.

Valuation Methods

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

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

Derivative Instruments Designated as Hedging Instruments

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

Cash Flow Hedges—A significant portion of the Company’s hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of natural gas and oil. The Company also uses interest rate swaps to hedge its exposure to variable interest rates on long-term debt. For cash flow hedge transactions in which the Company is hedging the variability of cash flows, changes in the fair value of the derivative are reported in accumulated other comprehensive income (loss) (AOCI), to the extent effective in offsetting changes in the hedging relationship, until earnings are affected by the hedged item. For cash flow hedge transactions that involve a forecasted transaction, the Company would discontinue hedge accounting if the occurrence of the forecasted transaction was determined to be no longer probable. The Company would reclassify any derivative gains or losses reported in AOCI to earnings when the forecasted item is included in earnings, if it should occur, or earlier, if it becomes probable that the forecasted transaction would not occur.

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

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

Derivative Instruments Held for Other Purposes

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

Statement of Income Presentation:

•

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

•

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

The Company recognizes revenue or expense from non-derivative energy-related contracts on a gross basis at the time of contract performance, settlement or termination.

2004 / Page 30

Notes to Consolidated Financial Statements, Continued

Property, Plant and Equipment

Property, plant and equipment, including additions and replacements, is recorded at original cost, including labor, materials, asset retirement costs, other direct costs and capitalized interest. The cost of repairs and maintenance, including minor additions and replacements, is charged to expense as incurred. In 2004, 2003 and 2002, the Company capitalized interest costs of $56 million, $67 million and $70 million, respectively.

The depreciable cost of gas utility and transmission property retired, less salvage value is charged to accumulated depreciation at retirement. Cost of removal collections from utility customers and expenditures not representing asset retirement obligations (AROs) are recorded as regulatory liabilities or regulatory assets. The Company records gains and losses upon retirement of nonregulated property based on the difference between proceeds received, if any, and the property’s undepreciated basis at the retirement date.

Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives or in the case of gas and oil producing properties, the units-of-production method.

The Company’s annual depreciation rates on property, plant and equipment (regulated and nonregulated) are as follows:


	2004	2003	2002
	(percent)
Transmission	2.42	2.45	2.38
Distribution	2.37	2.40	2.42
Storage	3.05	2.81	2.47
Gas gathering and processing	2.58	2.39	2.31
General and other	7.01	6.49	6.50

The Company follows the full cost method of accounting for gas and oil exploration and production activities prescribed by the Securities and Exchange Commission (SEC). Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. These capitalized costs are subject to a quarterly ceiling test. Under the ceiling test, amounts capitalized are limited to the present value of estimated future net revenues to be derived from the anticipated production of proved gas and oil reserves, assuming period-end pricing adjusted for cash flow hedges in place. If net capitalized costs exceed the ceiling test at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period. The ceiling test is performed separately for each cost center, with cost centers established on a country-by-country basis. Approximately 16% of the Company’s anticipated production is hedged by qualifying cash flow hedges, for which hedge-adjusted prices were used to calculate estimated future net revenue. Whether period-end market prices or hedge- adjusted prices were used for the portion of production that is hedged, there was no ceiling test impairment as of December 31, 2004. The Company adopted Staff Accounting Bulletin No. 106 (SAB 106) as of December 31, 2004 and, accordingly, excludes future cash flows associated with settling AROs that have been accrued on the balance sheet pursuant to SFAS No. 143, Accounting for Asset Retirement Obligations, from its calculations under the full cost ceiling test.

Depreciation of gas and oil producing properties is computed using the units-of-production method. Under the full cost method, the depreciable base of costs subject to amortization also includes estimated future costs to be incurred in developing proved gas and oil reserves, as well as capitalized asset retirement costs, net of projected salvage values. The costs of investments in unproved 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, determined on a property by property basis, over terms of underlying leases. Once a property has been evaluated, any remaining capitalized costs are then transferred to the depreciable base. In addition, gains or losses on the sale or other disposition of gas and oil properties are not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of natural gas and oil attributable to a cost center. See Asset Retirement Obligations for a discussion of gas and oil abandonment and dismantlement costs.

Goodwill and Intangible Assets

The Company evaluates goodwill for impairment annually, as of April 1st, and whenever an event occurs or circumstances change in the interim that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives.

Impairment of Long-Lived and Intangible Assets

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

Regulatory Assets and Liabilities

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

Asset Retirement Obligations

Beginning in 2003, the Company recognizes its AROs at fair value as incurred, capitalizing these amounts as costs of the related tangible long-lived assets. Due to the absence of relevant market information, fair value is estimated using discounted cash flow analyses. The Company reports the accretion of the liabilities due to the passage of time as an operating expense. Prior to 2003, the Company’s accounting and reporting practices for future dismantlement and restoration activities for its gas and oil wells

2004 / Page 31

Notes to Consolidated Financial Statements, Continued

and platforms recognized such costs as a component of depletion expense and included them in accumulated depreciation, depletion and amortization.

Amortization of Debt Issuance Costs

The Company defers and amortizes debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others.

Note 3. Newly Adopted Accounting Standards

2004

FSP FAS 142-2

The Company adopted Financial Accounting Standards Board (FASB) Staff Position 142-2, Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil- and Gas- Producing Entities, (FSP 142-2) in September 2004. FSP 142-2 was issued to clarify that an exception outlined in SFAS No. 142 includes the balance sheet classification of drilling and mineral rights of oil and gas producing entities. In accordance with the guidance in FSP 142-2, the Company continues to present its oil and gas drilling rights as tangible assets classified in property, plant and equipment.

SAB 106

In September 2004, the SEC issued SAB 106, which provides guidance to oil and gas companies following the full cost accounting method regarding the application of SFAS No. 143. SAB 106 requires companies calculating the full cost ceiling test to exclude future cash outflows associated with settling AROs that have been accrued on the balance sheet as required by SFAS No. 143. However, estimated dismantlement and abandonment costs related to future development activities, which are not required to be accrued under SFAS No.143, should continue to be included in the full cost ceiling test. The Company adopted the provisions of SAB 106 during the fourth quarter of 2004. There was no financial statement impact associated with the adoption of SAB 106.

2003

SFAS No. 143

Effective January 1, 2003, the Company adopted SFAS No. 143, which provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. The adoption of SFAS No. 143 resulted in an after-tax loss of $5 million, representing the cumulative effect of a change in accounting principle. The impact of adopting SFAS No. 143 for 2003, other than the cumulative effect of a change in accounting principle, was not material.

EITF 03-11

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

FIN 46R

On December 31, 2003, the Company adopted FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, (FIN 46R) for its interests in special purpose entities. FIN 46R addresses the consolidation of variable interest entities (VIEs), which are entities that are not controllable through voting interests or in which the VIEs’ equity investors do not bear the residual economic risks and rewards.

Under FIN 46R, the Company consolidated a special purpose lessor entity through which the Company had financed and leased a new power generation project. As a result, the Consolidated Balance Sheet as of December 31, 2003 reflects an additional $223 million in net property, plant and equipment and deferred charges and an additional $234 million of related debt. This resulted in additional depreciation expense of approximately $7 million in 2004. The cumulative effect of adopting FIN 46R for its interest in the special purpose entity was an after-tax charge of $6 million, representing depreciation expense associated with the consolidated assets.

In 2001, the Company established CNG Capital Trust I that sold trust preferred securities to third party investors. The Company received the proceeds from the sale of the trust preferred securities in exchange for junior subordinated debt notes issued by the Company to be held by the trust. Upon adoption of FIN 46R, the Company began reporting as long-term debt its junior subordinated notes held by the trust rather than the trust preferred securities. As a result in 2004, the Company reported interest expense on the junior subordinated notes rather than preferred distribution expense on the trust preferred securities.

Pro Forma Information Reflecting Adoption of New Standards

Disclosure requirements associated with the adoption of FIN 46R and SFAS No. 143 require a presentation of pro forma net income for 2002 as if the Company had applied the provisions of those standards as of January 1, 2002. Other standards adopted during 2004 and 2003 do not require pro forma information and are excluded from the amounts presented below.


	2002
(millions)
Reported net income	$	638
Adjusted net income		629

Note 4. Recently Issued Accounting Standards

SFAS No. 151

In November 2004, the FASB issued SFAS No. 151, Inventory Costs—an amendment of ARB No. 43, Chapter 4, which clarifies that abnormal amounts of idle facility expense, handling costs, freight, and wasted materials (spoilage) should be recognized as current period charges, and requires that in manufacturing oper -

2004 / Page 32

Notes to Consolidated Financial Statements, Continued

ations, allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facility. The Company will adopt the provisions of this standard prospectively beginning January 1, 2006 and does not expect the adoption to have a material impact on its results of operations and financial condition.

SFAS No. 153

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

Note 5. Acquisitions

Cove Point LNG Limited Partnership

In September 2002, the Company acquired 100% ownership of Cove Point LNG Limited Partnership (Cove Point), a cost-based rate-regulated entity, from a subsidiary of The Williams Companies for $225 million in cash. The Company recorded $75 million of goodwill, representing the excess of the purchase price over the regulatory basis of Cove Point’s assets acquired and liabilities assumed. Cove Point’s assets include an LNG natural gas import and storage facility located near Baltimore, Maryland and an approximately 85-mile natural gas pipeline. Cove Point became fully operational in August 2003. Cove Point is included in the Energy segment and the goodwill arising from the acquisition was allocated to that segment for goodwill impairment-testing purposes.

Note 6. Operating Revenue

The Company’s operating revenue consists of the following:


Year Ended December 31,	2004		2003		2002
(millions)
Regulated gas sales	$	1,422	$	1,259	$	876
Nonregulated electric sales		390		232		124
Nonregulated gas sales:
External customers		959		876		761
Affiliated customers		1,037		655		122
Gas transportation and storage		819		767		737
Gas and oil production		1,297		1,177		990
Other		640		347		290
Total operating revenue	$	6,564	$	5,313	$	3,900

Note 7. International Investments

CNG International Corporation (CNGI) was engaged in energy-related activities outside of the continental United States, primarily through equity investments in Australia and Argentina. After completing the CNG acquisition, the Company’s management committed to a plan to dispose of the entire CNGI operation consistent with its strategy to focus on its core business.

During 2003, the Company recognized impairment losses totaling $78 million ($65 million after-tax) related primarily to investments in a pipeline business located in Australia and a small generation facility in Kauai, Hawaii that was sold in December 2003 for cash proceeds of $42 million. These impairment losses were reported in other income ($62 million) and other operations and maintenance expense ($16 million) in the Consolidated Statement of Income. The impairment losses represented adjustments to the assets’ carrying amounts to reflect the Company’s then current evaluation of fair market value less estimated costs to sell, which were derived from a combination of actual 2003 transactions, management estimates, and other fair market value indicators.

In 2004, the Company received cash proceeds of $52 million and recognized a gain in other income of $13 million from the sale of a portion of the Australian pipeline business in which CNGI held an investment. The Company also recognized an $18 million benefit from an adjustment to the carrying amount of this investment to reflect its then current estimate of fair value, less estimated costs to sell.

At December 31, 2004, the Company’s remaining CNGI investment is accounted for at fair value. Management expects this $2 million investment to be sold by the end of 2006.

Note 8. Income Taxes

Details of income tax expense were as follows:


Year Ended December 31,	2004			2003			2002
(millions)
Current expense:
Federal	$	72		$	113		$	(74	)
State		12			20			(7	)
Total current		84			133			(81	)
Deferred expense:
Federal		394			228			373
State		5			13			22
Total deferred		399			241			395
Amortization of deferred investment tax credits—net		(1	)		(2	)		(2	)
Total income tax expense	$	482		$	372		$	312

2004 / Page 33

Notes to Consolidated Financial Statements, Continued

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


Year Ended December 31,	2004		2003		2002
(millions)
U.S statutory rate	35.0	%	35.0	%	35.0	%
Increases (reductions) resulting from:
Amortization of investment tax credits	(0.1	)	(0.1	)	(0.2	)
Nonconventional fuel credit	—		—		(1.0	)
State taxes, net of federal benefit	0.8		2.2		1.0
Employee pension and other benefits	(0.6	)	(1.1	)	(1.2	)
Employee stock ownership plan deduction	(0.2	)	(0.4	)	(0.6	)
Valuation allowance	1.6		1.5		—
Other, net	(0.7	)	(0.6	)	(0.2	)
Effective tax rate	35.8	%	36.5	%	32.8	%

The Company’s 2004 and 2003 effective tax rates were negatively impacted by the expiration of nonconventional fuel tax credits and the establishment of the valuation allowance related to federal loss carryforwards at CNGI that are not expected to be utilized. The Company’s 2003 effective tax rate was also negatively impacted by higher state tax expense.

Deferred income taxes reflect the net effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.

The Company’s net deferred income taxes consist of the following:


	At December 31,
	2004			2003
(millions)
Deferred income tax assets:
Other comprehensive income	$	491		$	294
Deferred investment tax credits		3			4
Unrecovered purchased gas costs		34			32
Loss and credit carryforwards		227			151
Other		—			61
Valuation allowance		(50	)		(20	)
Total deferred income tax assets		705			522
Depreciation method and plant basis differences		448			363
Income taxes recoverable through future rates		40			35
Intangible drilling costs		891			764
Partnership basis differences		406			296
Geological, geophysical and other exploration differences		387			343
Postretirement and pension benefits		318			274
Deferred state income taxes		219			215
Other		26			—
Total deferred income tax liabilities		2,735			2,290
Total net deferred income tax liabilities	$	2,030		$	1,768

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

•

Federal loss carryforwards of $400 million that expire if unutilized during the period 2005 through 2024. A valuation allowance on $115 million in carryforwards has been established due to the uncertainty of realizing these future deductions;

•

State loss carryforwards of $1.0 billion that expire if unutilized during the period 2005 through 2024. A valuation allowance on $322 million in carryforwards has been established due to the uncertainty of realizing these future deductions; and

•

Federal minimum tax credits of $44 million that do not expire.

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

American Jobs Creation Act of 2004 (the Act)

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

2004 / Page 34

Notes to Consolidated Financial Statements, Continued

Note 9. Hedge Accounting Activities

The Company is exposed to the impact of market fluctuations in the price of natural gas and oil and to the interest rate risks of its business operations. The Company uses derivative instruments to mitigate its exposure to these risks and designates derivative instruments as fair value or cash flow hedges for accounting purposes. Selected information about the Company’s hedge accounting activities follows:


	2004			2003			2002
(millions)
Portion of losses on hedging instruments determined to be ineffective and included in net income:
Fair value hedges	$	(2	)	$	(1	)	$	—
Cash flow hedges		(1	)		(1	)		(9	)
Net ineffectiveness	$	(3	)	$	(2	)	$	(9	)
Portion of gains (losses) on hedging instruments attributable to changes in options’ time value excluded from measurement of effectiveness and included in net income:
Fair value hedges	$	1		$	—		$	(1	)
Cash flow hedges		103			6			—
Total change in options’ time value	$	104		$	6		$	(1	)

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


	Accumulated Other Comprehensive Income (Loss) After Tax			Portion Expected to be Reclassified to Earnings during the Next 12 Months After Tax			Maximum Term
(dollar amount in millions)
Commodities:
Gas	$	(541	)	$	(288	)	38 months
Oil		(307	)		(135	)	36 months
Interest Rate		(1	)		—		119 months
Total	$	(849	)	$	(423	)

The actual amounts that will be reclassified to earnings in 2005 will vary from the expected amounts presented above as a result of changes in market prices and interest rates. The effect of amounts being reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies.

As a result of damage to certain offshore production facilities in the Gulf of Mexico caused by Hurricane Ivan, and the related loss of forecasted oil production for the period from mid-September 2004 to May 2005, the Company discontinued certain cash flow hedges effective September 14, 2004. In connection with the discontinuance of these cash flow hedges, the Company reclassified $71 million of pre-tax losses from AOCI to earnings in 2004. These amounts were reported in other operations and maintenance expense in the Consolidated Statements of Income.

Note 10. Property, Plant and Equipment

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


December 31,	2004		2003
(millions)
Utility:
Transmission	$	1,829	$	1,716
Distribution		1,999		1,917
Storage		1,023		999
Gas gathering and processing		418		416
General and other		166		179
Plant under construction		163		123
Total utility		5,598		5,350
Nonutility:
Exploration and production properties being amortized:
Proved		9,346		8,077
Unproved		1,029		941
Unproved exploration and production properties not being amortized		919		1,099
Other—including plant under construction		328		387
Total nonutility		11,622		10,504
Total property, plant and equipment	$	17,220	$	15,854

Costs of unproved properties capitalized under the full cost method of accounting that were excluded from amortization at December 31, 2004 and the years in which the excluded costs were incurred, are as follows:


	Total		2004		2003		2002		Years Prior
(millions)
Property acquisition costs	$	661	$	36	$	54	$	50	$	521
Exploration costs		121		43		31		25		22
Capitalized interest		137		49		54		25		9
Total	$	919	$	128	$	139	$	100	$	552

There were no significant properties under development, as defined by the SEC, excluded from amortization at December 31, 2004. As gas and oil reserves are proved through drilling or as properties are deemed to be impaired, excluded costs and any related reserves are transferred on an ongoing, well-by-well basis into the amortization calculation.

Amortization rates for capitalized costs under the full cost method of accounting in thousand cubic feet (mcf) equivalent were $1.35, $1.26 and $1.24 for 2004, 2003 and 2002, respectively.

Volumetric Production Payment Transactions

In 2004, the Company received $413 million in cash for the sale of a fixed-term overriding royalty interest in certain of its natural gas reserves for the period May 2004 through April 2008. The sale reduced the Company’s proved natural gas reserves by approximately 83 billion cubic feet (bcf). While the Company is obligated

2004 / Page 35

Notes to Consolidated Financial Statements, Continued

under the agreement to deliver to the purchaser its portion of future natural gas production from the properties, it retains control of the properties and rights to future development drilling. If production from the properties is inadequate to deliver approximately 83 bcf of natural gas scheduled for delivery to the purchaser, the Company has no obligation to make up the shortfall. Cash proceeds received from this VPP transaction were recorded as deferred revenue. The Company will recognize revenue from the transaction as natural gas is produced and delivered to the purchaser. The Company also entered into a VPP transaction in 2003 receiving proceeds of $266 million for approximately 66 bcf for the period August 2003 through August 2007.

Note 11. Goodwill and Intangible Assets

There was no impairment of or material change to the carrying amount and segment allocation of goodwill in 2004.

All of the Company’s intangible assets, other than goodwill, are subject to amortization. Amortization expense for intangible assets was $22 million, $18 million and $19 million for 2004, 2003 and 2002, respectively. There were no material acquisitions of intangible assets in 2004 or 2003. Intangible assets are included in other assets on the Consolidated Balance Sheets. The components of intangible assets at December 31, 2004 and 2003 were as follows:


	2004				2003
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
(millions)
Software and software licenses	$	208	$	96	$	193	$	88
Other		27		17		22		13
Total	$	235	$	113	$	215	$	101

Annual amortization expense for intangible assets is estimated to be $19 million for 2005, $18 million for 2006, $16 million for 2007, $13 million for 2008 and $10 million for 2009.

Note 12. Regulatory Assets and Liabilities

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


	At December 31,
	2004		2003
(millions)
Regulatory assets:
Unrecovered gas costs	$	52	$	55
Regulatory assets—current⁽¹⁾		52		55
Other postretirement benefits⁽²⁾		48		44
Income taxes recoverable through future rates⁽³⁾		199		183
Customer bad debts⁽⁴⁾		73		64
Other		49		37
Regulatory assets—non-current		369		328
Total regulatory assets	$	421	$	383
Regulatory liabilities:
Amounts payable to customers	$	2	$	3
Estimated rate contingencies and refunds⁽⁵⁾		13		13
Regulatory liabilities—current⁽⁶⁾		15		16
Provision for future cost of removal⁽⁷⁾		221		212
Other		2		—
Regulatory liabilities—non-current		223		212
Total regulatory liabilities	$	238	$	228

(1)

Reported in other current assets.

(2)

Pending the expected recovery of costs recognized under SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, the Company’s rate-regulated subsidiaries have deferred the differences between SFAS No. 106 costs and amounts included in rates.

(3)

Income taxes recoverable through future rates represent amounts to be collected from customers related to the recognition of additional deferred income taxes not previously recorded under past ratemaking practices.

(4)

The Public Utilities Commission of Ohio (Ohio Commission) has authorized the collection of previously deferred costs of $51 million associated with certain uncollectible customer accounts from 2001 over five years through the tracker rider effective in 2004. The Ohio Commission has also authorized the deferral and recovery of excess bad debt costs incurred in 2003 and thereafter for certain uncollectible customer accounts not contemplated in current base rate recoveries. The total deferral of 2004 and 2003 excess uncollectible amounts was $17 million and $13 million, respectively.

(5)

Estimated rate contingencies and refunds are associated with certain increases in prices by the Company’s rate regulated utilities and other ratemaking issues that are subject to final modification in regulatory proceedings.

(6)

Reported in other current liabilities.

(7)

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

At December 31, 2004, approximately $124 million of the Company’s regulatory assets represented past expenditures on which it does not earn a return. These expenditures consist primarily of unrecovered gas costs and customer bad debts. Unrecovered gas costs and the ongoing portion of bad debts are recovered within two years. The previously deferred bad debts will be recovered over a four-year period.

2004 / Page 36

Notes to Consolidated Financial Statements, Continued

Note 13. Asset Retirement Obligations

The Company’s AROs are primarily associated with the retirement of certain natural gas pipelines and the dismantlement and restoration activities for its gas and oil wells and platforms. In addition, the Company has AROs related to its natural gas gathering, storage, transmission and distribution systems, including approximately 2,300 gas storage wells in the Company’s underground natural gas storage network. These obligations result from certain safety requirements to be performed at the time any pipeline or storage well is abandoned. However, the Company expects to operate its natural gas gathering, storage, transmission and distribution systems in perpetuity. Thus, AROs for those assets will not be reflected in the Company’s Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. Generally, this will occur when expected retirement or abandonment dates for individual pipelines or storage wells are determined by the Company’s operational planning. The changes to the Company’s AROs during 2004 were as follows:


	Amount
(millions)
Asset retirement obligations at December 31, 2003	$	241
Obligations incurred during the period		17
Obligations settled during the period		(14	)
Accretion expense		12
Revisions in estimated cash flows		(2	)
Other		(1	)
Asset retirement obligations at December 31, 2004⁽¹⁾	$	253

(1)

Consists of $251 million reported in other non-current liabilities and $2 million reported in other current liabilities.

Note 14. Short-Term Debt and Credit Agreements

Joint Credit Facilities

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

At December 31, 2004, total outstanding commercial paper supported by the joint credit facilities was $573 million, none of which were the Company’s borrowings. At December 31, 2003, total outstanding commercial paper supported by previous credit agreements was $1.44 billion, of which the Company’s borrowings were $151 million, with a weighted-average interest rate of 1.24%.

At December 31, 2004 and 2003, total outstanding letters of credit supported by the joint credit facilities were $183 million and $85 million, respectively, all of which were issued on the behalf of other Dominion subsidiaries.

Other Credit Facilities

In August 2004, the Company entered into a $1.5 billion three-year revolving credit facility that terminates in August 2007. This credit facility is being used to support the issuance of commercial paper and letters of credit to provide collateral required by counterparties on derivative financial contracts used by the Company in its risk management strategies for its gas and oil production. At December 31, 2004, outstanding letters of credit under this facility totaled $555 million. At December 31, 2003, outstanding letters of credit under the previous credit facility totaled $820 million.

In addition to the facilities above, in June and August of 2004, the Company entered into two $100 million letter of credit agreements that terminate in June 2007 and August 2009, respectively. Additionally, in October 2004, the Company entered into three letter of credit agreements totaling $700 million that terminate in April 2005 and are not expected to be renewed. These five agreements support letter of credit issuances, providing collateral required on derivative financial contracts used by the Company in its risk management strategies for gas and oil production. At December 31, 2004, outstanding letters of credit under these agreements totaled $900 million.

2004 / Page 37

Notes to Consolidated Financial Statements, Continued

Note 15. Long-Term Debt

The Company’s long-term debt consists of the following:


		At December 31,
	2004 Weighted Average Coupon⁽¹⁾	2004			2003
(millions)
Unsecured Debentures and Senior Notes:
5.375% to 7.375%, due 2005 to 2008	6.16%	$	1,000		$	1,400
5.0% to 6.85%, due 2010 to 2027	6.12%		2,200			1,800
6.875%, due 2026⁽²⁾			150			150
Unsecured Senior Subordinated Debt:
9.25%, due 2004			—			88
Secured Bank Debt
Variable Rate, due 2006⁽³⁾	2.55%		234			234
Notes Payable to Affiliates:
Unsecured Junior Subordinated Notes Payable to Affiliated Trust, 7.8%, due 2041			206			206
			3,790			3,878
Fair value hedge valuation⁽⁴⁾			21			39
Amount due within one year	7.375%		(150	)		(501	)
Unamortized discount and premium, net			(1	)		3
Total long-term debt		$	3,660		$	3,419

(1)

Represents weighted-average coupon rate for debt outstanding as of December 31, 2004.

(2)

At the option of holders in October 2006, these notes are subject to redemption at 100% of the principal amount plus accrued interest.

(3)

Represents debt associated with a special purpose lessor entity that is consolidated in accordance with FIN 46R. The debt is nonrecourse to the Company and is secured by the entity’s property, plant and equipment of $214 million and $221 million at December 31, 2004 and 2003, respectively.

(4)

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

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


2005	2006		2007		2008		2009		Thereafter		Total
$150	$	734	$	200	$	150	$	—	$	2,556	$	3,790

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

Junior Subordinated Notes Payable to Affiliated Trust

In 2001, Dominion CNG Capital Trust I (trust), a finance subsidiary of the Company, which holds 100% of the voting interests, sold 8 million 7.8% trust preferred securities for $200 million, representing preferred beneficial interests and 97% beneficial ownership in the assets held by the trust. In exchange for the $200 million realized from the sale of the trust preferred securities and $6 million of common securities that represent the remaining 3% beneficial ownership interest in the assets held by the trust, the Company issued $206 million of its 2001 7.8% junior subordinated notes due October 31, 2041. The junior subordinated notes constitute 100% of the trust’s assets. The trust must redeem the trust preferred securities when the junior subordinated notes are repaid or if redeemed prior to maturity.

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

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

2004 / Page 38

Notes to Consolidated Financial Statements, Continued

Note 16. Shareholder’s Equity

Other paid-in capital

In exchange for a reduction in amounts payable to Dominion, the Company recognized $41 million and $6 million of additional paid-in capital in 2004 and 2003, respectively. In 2003, Dominion made a $600 million equity contribution to the Company and the Company used the proceeds to reduce the money pool borrowings of the Company’s subsidiaries.

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


	At December 31,
(millions)	2004			2003

Net unrealized losses on derivatives, net of tax	$	(849	)	$	(570	)
Currency translation adjustment		—			33
Total accumulated other comprehensive loss	$	(849	)	$	(537	)

Note 17. Dividend Restrictions

The 1935 Act and related regulations issued by the SEC impose restrictions on the transfer and receipt of funds by a registered holding company from its subsidiaries, including a general prohibition against loans or advances being made by the subsidiaries to benefit the registered holding company. Under the 1935 Act, registered holding companies and their subsidiaries may pay dividends only from retained earnings, unless the SEC specifically authorizes payments from other capital accounts. The Company received dividends from its subsidiaries of $481 million, $405 million and $345 million in 2004, 2003, and 2002, respectively.

At December 31, 2004, the Company’s consolidated subsidiaries had approximately $2.2 billion in capital accounts other than retained earnings, representing capital stock, other paid-in capital and AOCI. The Company had approximately $3.5 billion in capital accounts other than retained earnings at December 31, 2004. Generally such amounts are not available for the payment of dividends by affected subsidiaries, or by the Company itself, without specific authorization by the SEC. In response to a Dominion request, the SEC granted relief in 2000, authorizing payment of dividends by the Company from other capital accounts to Dominion in amounts up to $1.6 billion, representing the Company’s retained earnings prior to Dominion’s acquisition of the Company. The SEC granted further relief in 2004, authorizing the Company’s nonutility subsidiaries to pay dividends out of capital or unearned surplus in situations where such subsidiary has received excess cash from an asset sale, engaged in a restructuring, or is returning capital to an associate company.

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

See Note 15 for a description of potential restrictions on dividend payments by the Company in connection with the deferral of distribution payments on trust preferred securities.

Note 18. Employee Benefit Plans

The Company provides certain benefits to eligible active employees, retirees and qualifying dependents. Under the terms of its benefit plans, the Company reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.

Pension benefits, for the Company’s employees not represented by recognized bargaining units, are covered by Dominion’s pension plan, which provides benefits to multiple Dominion subsidiaries. The Company recognized $50 million and $63 million of net periodic pension credits in 2004 and 2003, respectively, related to the plan. The Company made no contributions to the plan in either 2004, 2003 or 2002.

The Company sponsors qualified pension plans that cover employee groups represented by collective bargaining units. Retirement benefits payable under all plans are based primarily on years-of-service, age and compensation. The Company’s contributions to the plans are generally determined in accordance with the provisions of the Employment Retirement Income Security Act of 1974.

The Company’s measurement date for the majority of its employee benefit plans is December 31. The Company uses a market-related value of pension plan assets to determine the expected return on pension plan assets, a component of net periodic pension cost. The market-related value recognizes changes in fair value on a straight-line basis over a four-year period. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains and losses.

Retiree health care and life insurance benefits, for the Company’s employees not represented by recognized bargaining units, are covered by Dominion’s other postretirement benefit plans. The Company sponsors other postretirement benefit plans that cover employee groups represented by collective bargaining units. Annual premiums are based on several factors such as age, retirement date and years-of service.

On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Medicare Act) was signed into law. The Medicare Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Based on an analysis performed by a third party actuary, the Company has determined that the prescription drug benefit offered under its other postretirement benefit plans is at least actuarially equivalent to Medicare Part D and therefore expects to receive the federal subsidy offered under the Medicare Act. The Company expects to receive subsidies, for employees represented by collective bargaining units, of approximately $1 million annually

2004 / Page 39

Notes to Consolidated Financial Statements, Continued

for the years 2006 through 2009 and expects to receive approximately $8 million for the period beginning 2010 through 2014. The Company considered the passage of the Medicare Act a significant event requiring remeasurement of its accumulated postretirement benefit obligation on December 8, 2003. The Company will amortize the unrecognized actuarial gains associated with the benefits of the subsidy over the average remaining service period of plan participants in accordance with SFAS No. 106.

The following tables summarize information for the Company’s pension and other postretirement benefit plans for employees represented by collective bargaining units, including the changes in the pension and other postretirement benefit plan obligations and plan assets and a statement of the plans’ funded status:



	Year Ended December 31,
	Pension Benefits						Other Postretirement Benefits
	2004			2003			2004			2003
(millions)
Change in benefit obligation:
Benefit obligation at beginning of year	$	491		$	453		$	427		$	316
Service cost		11			9			17			15
Interest cost		30			30			26			25
Plan amendments		5			—			(2	)		—
Actuarial (gain) loss		22			30			(42	)		116
Actuarial gain related to Medicare Part D		—			—			—			(24	)
Benefits paid		(32	)		(31	)		(24	)		(21	)
Benefit obligation at end of year	$	527		$	491		$	402		$	427
Change in plan assets:
Fair value of plan assets at beginning of year	$	1,108		$	972		$	173		$	131
Actual return on plan assets		124			167			15			24
Employer contributions		—			—			38			38
Benefits paid from plan assets		(32	)		(31	)		(22	)		(20	)
Fair value of plan assets at end of year	$	1,200		$	1,108		$	204		$	173
Funded status	$	673		$	617		$	(198	)	$	(254	)
Unrecognized net transition (asset) obligation		—			(3	)		46			51
Unrecognized net actuarial (gain) loss		(80	)		(79	)		106			161
Unamortized prior service cost		17			13			(3	)		(2	)
Prepaid (accrued) benefit cost	$	610		$	548		$	(49	)	$	(44	)
Amounts recognized in the Consolidated Balance Sheets at December 31⁽¹⁾:
Prepaid pension cost	$	984		$	872			—			—
Accrued benefit liability		—			—		$	(97	)	$	(87	)

(1)

Amounts represent all benefit plans in which the Company participates, including benefit plans covering multiple Dominion subsidiaries.

The accumulated benefit obligation for the Company-sponsored defined benefit pension plans was $482 million and $451 million at December 31, 2004 and 2003, respectively. Under its funding policies, the Company evaluates plan funding requirements annually, usually in the third quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and other factors, the amount of contributions for the current year, if any, is determined at that time.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid for employees represented by collective bargaining units:


	Pension Benefits		Other Postretirement Benefits
(millions)
2005	$	30	$	22
2006		30		23
2007		30		25
2008		30		25
2009		31		26
2010-2014		176		144

2004 / Page 40

Notes to Consolidated Financial Statements, Continued

The Company’s overall objective for investing its pension and other postretirement plan assets is to achieve the best possible long-term rates of return commensurate with prudent levels of risk. To minimize risk, funds are broadly diversified among asset classes, investment strategies and investment advisors. The strategic target asset allocation for the Company’s pension funds is 45% U.S. equity securities; 8% non-U.S. 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. The Company’s asset allocations for pension plans and other postretirement benefit plans for employees represented by collective bargaining units at December 31, 2004 and 2003 were as follows:



	Pension Plans						Other Postretirement Plans
	2004			2003			2004			2003
	Fair Value		% of Total	Fair Value		% of Total	Fair Value		% of Total	Fair Value		% of Total
(millions)
Equity securities:
U.S.	$	522	44	$	492	44	$	89	44	$	74	43
International		155	13		121	11		20	10		18	10
Debt securities		280	23		254	23		82	40		67	39
Real estate		88	7		78	7		3	1		2	1
Other		155	13		163	15		10	5		12	7
Total	$	1,200	100	$	1,108	100	$	204	100	$	173	100

The components of the provision for net periodic benefit cost were as follows for the year ended December 31:


	Pension Benefits									Other Postretirement Benefits
	2004			2003			2002			2004			2003			2002
(millions)
Service cost	$	11		$	9		$	8		$	17		$	15		$	10
Interest cost		30			30			29			26			25			20
Expected return on assets		(100	)		(99	)		(107	)		(13	)		(10	)		(8	)
Prior service cost amortization		1			1			—			—			—			—
Transition obligation (asset) amortization		(3	)		(3	)		(5	)		6			5			7
Amortization of net (gain) loss		(1	)		(9	)		(16	)		10			10			2
Net periodic benefit cost (credit)	$	(62	)	$	(71	)	$	(91	)	$	46		$	45		$	31

Company’s net periodic benefit cost (credit)⁽¹⁾	$	(112	)	$	(134	)	$	(171	)	$	63		$	65		$	46

(1)

Amounts represent all benefit plans in which the Company participates, including benefit plans covering multiple Dominion subsidiaries.

Significant assumptions used in determining the net periodic cost recognized in the 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%	8.00%	8.00%	6.50%
Rate of increase for compensation	4.00%	4.00%	4.00%	4.00%	4.00%	4.00%
Medical cost trend rate⁽¹⁾				9.00%	9.00%	9.00%

(1)

The medical cost trend rate for 2004 is assumed to gradually decrease to 5.00% by 2008 and continues at that rate for years thereafter.

Significant assumptions used in determining the projected pension and postretirement benefit obligations recognized in the Consolidated Balance Sheets were as follows, on a weighted-average basis:


	Pension Benefits				Other Postretirement Benefits
	2004		2003		2004		2003
Discount rate	6.00	%	6.25	%	6.00	%	6.25	%
Rate of increase for compensation	4.00	%	4.00	%	4.00	%	4.00	%

The Company determines the expected long-term rates of return on plan assets for pension plans and other postretirement benefit plans by using a combination of:

•

Historical return analysis to determine expected future risk premiums;

•

Forward-looking return expectations derived from the yield on long term bonds and the price earnings ratios of major stock market indices;

•

Expected inflation and risk-free interest rate assumptions, and

•

The types of investments expected to be held by the plans.

Assisted by an independent actuary, management develops assumptions, which are then compared to the forecasts of other independent investment advisors to ensure reasonableness. An internal committee selects the final assumptions. Discount rates are determined from analyses performed by a third party actuarial firm of AA/Aa rated bonds with cash flows matching the expected payments to be made under the Company’s plans.

2004 / Page 41

Notes to Consolidated Financial Statements, Continued

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in the assumed health care cost trend rate would have had the following effects:


	Other Postretirement Benefits
	One Percentage Point Increase		One Percentage Point Decrease
(millions)
Effect on total service and interest cost components for 2004	$	5	$	(8	)
Effect on postretirement benefit obligation at December 31, 2004	$	54	$	(44	)

The Company also participates in Dominion-sponsored employee savings plans that cover substantially all employees. Employer matching contributions of $8 million, $8 million and $7 million were incurred in 2004, 2003 and 2002, respectively.

Certain regulatory authorities have held that amounts recovered in rates for other postretirement benefits in excess of benefits actually paid during the year must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, certain subsidiaries fund postretirement benefit costs through Voluntary Employees’ Beneficiary Associations. The remaining subsidiaries do not prefund postretirement benefit costs but instead pay claims as presented.

Note 19. Commitments and Contingencies

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

Long-Term Purchase Agreements

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


	2005		2006		2007		2008		2009		Later Years		Total
(millions)
Production handling for gas and oil production operations⁽¹⁾	$	56	$	54	$	51	$	38	$	23	$	27	$	249

(1)

Payments under this contract totaled $22 million and $10 million for 2004 and 2003, respectively. No payments were made under this contract in 2002.

Lease Commitments

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


2005	2006		2007		2008		2009		Thereafter		Total
$32	$	30	$	29	$	27	$	22	$	146	$	286

Rental expense totaled $50 million, $40 million and $33 million for 2004, 2003 and 2002, respectively, the majority of which is reflected in other operations and maintenance expense.

Environmental Matters

The Company is subject to costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations and can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations of the Company. The Company may sometimes seek recovery of environmental-related expenditures through regulatory proceedings.

The Company has determined that it is associated with 16 former manufactured gas plant sites. Studies conducted by other utilities at their former manufactured gas plants have indicated that their sites contain coal tar and other potentially harmful materials. None of the 16 former sites with which the Company is associated is under investigation by any state or federal environmental agency, and no investigation or action is currently anticipated. At this time, it is not known to what degree these sites may contain environmental contamination. The Company is not able to estimate the cost, if any, that may be required for the possible remediation of these sites.

Before being acquired by Dominion in 2001, Louis Dreyfus Natural Gas Corp. (Louis Dreyfus) was one of numerous defendants in a lawsuit consolidated and pending in the 93rd Judicial District Court in Hidalgo County, Texas. The lawsuit alleges that gas wells and related pipeline facilities operated by Louis Dreyfus and facilities operated by other defendants caused an underground hydrocarbon plume in McAllen, Texas. The plaintiffs claim that they have suffered damages, including property damage and lost profits as a result of the alleged plume. Although the results of litigation are inherently unpredictable, the Company does not expect the ultimate outcome of the case to have a material adverse impact on its financial position or results of operations, cash flows or financial position.

Guarantees, Letters of Credit and Surety Bonds

As of December 31, 2004, the Company had issued $1.6 billion of guarantees, including: $1.2 billion to support commodity transactions of subsidiaries; $200 million for subsidiary debt and $183 million for guarantees supporting other agreements of sub -

2004 / Page 42

Notes to Consolidated Financial Statements, Continued

sidiaries. The Company had also purchased $49 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $1.46 billion. The Company enters into these arrangements to facilitate commercial transactions by its subsidiaries with third parties. While the majority of these guarantees do not have a termination date, the Company may choose at any time to limit the applicability of such guarantees to future transactions. To the extent that a liability subject to a guarantee has been incurred by a consolidated subsidiary, that liability is included in the Company’s Consolidated Financial Statements. The Company is not required to recognize liabilities for guarantees on behalf of its subsidiaries in the Consolidated Financial Statements, unless it becomes probable that the Company will have to perform under the guarantees. No such liabilities have been recognized as of December 31, 2004. The Company believes it is unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries’ obligations.

Indemnifications

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

Enron Bankruptcy

During 2002, the Company terminated all outstanding and open positions with Enron. Dominion submitted a claim in the Enron bankruptcy case for the value of the Company’s contracts, measured at the effective dates of contract termination. The bankruptcy court’s approval of a settlement of Dominion’s claim in the proceeding during the first quarter of 2004 did not require material adjustments to the Company’s estimate of collectibility of amounts due form Enron and, accordingly, did not materially affect the Company’s results of operations or cash flows.

Note 20. Fair Value of Financial Instruments

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


	2004				2003
	Carrying Amount		Estimated Fair Value⁽¹⁾		Carrying Amount		Estimated Fair Value⁽¹⁾
(millions)
Long-term debt	$	3,604	$	3,825	$	3,714	$	3,956
Junior subordinated notes payable to affiliated trust		206		221		206		228

(1)

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

Note 21. Credit Risk

Credit risk is the risk of financial loss to the Company if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, Dominion and its subsidiaries, including the Company, maintain credit policies, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction. Amounts reported as margin deposit liabilities represent funds held by the Company that resulted from various trading counterparties exceeding agreed-upon credit limits established by the Company. Amounts reported as margin deposit assets represent funds held on deposit by various trading counterparties that resulted from the Company exceeding agreed-upon credit limits established by the counterparties. As of December 31, 2004 and 2003, the Company had margin deposit assets of $88 million and $59 million, respectively included in other current assets. The Company had no margin deposit liabilities as of December 31, 2004 or 2003.

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

The Company sells natural gas and provides distribution services to residential, commercial and industrial customers and provides transmission services to utilities and other energy companies. In addition, the Company enters into contracts with various companies in the energy industry for purchases and sales of energy-related commodities, including natural gas and oil. Except for gas and oil exploration and production business activities, these transactions principally occur in the Northeast, Midwest and Mid-Atlantic regions of the United States. Management does not believe that this geographic concentration contributes significantly to the Company’s overall exposure to credit risk.

2004 / Page 43

Notes to Consolidated Financial Statements, Continued

Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers.

The Company’s exposure to credit risk is concentrated primarily within its sales of gas and oil production and energy marketing, including its hedging activities, as the Company transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. At December 31, 2004, gross credit exposure related to these transactions totaled $404 million, reflecting the unrealized gains for contracts carried at fair value plus any outstanding receivables (net of payables, where netting agreements exist). Of this amount, investment grade counterparties represent 68% and no single counterparty exceeded 5%. The Company held no collateral at December 31, 2004.

Note 22. Related Party Transactions

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

Transactions with Affiliates

The Company transacts with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. The Company also enters into certain derivative commodity contracts with affiliates. These contracts, which are principally comprised of commodity swaps and options, are used by the Company to manage commodity price risks associated with the purchases and sales of natural gas. The Company designates the majority of these contracts as cash flow hedges for accounting purposes.

Presented below are affiliated transactions, including net realized gains and losses on affiliated commodity derivative contracts, recorded in operating revenue and operating expenses:


	Year Ended December 31,
	2004		2003		2002
(millions)
Purchases of natural gas from affiliates	$	527	$	613	$	270
Sales of natural gas to affiliates		1,037		655		122
Sales of gas transportation and storage services to affiliates		19		29		32
Purchases of electric fuel and energy from affiliates		196		80		37
Sales of electricity to affiliates		34		27		17

At December 31, 2004 and 2003, the Company’s Consolidated Balance Sheets include derivative assets with affiliates of $249 million and $240 million, respectively, and derivative liabilities with affiliates of $49 million and $48 million, respectively. Unrealized gains or losses, representing the effective portion of the changes in fair value of those derivative contracts that had been designated as hedges, are included in the AOCI on the Consolidated Balance Sheets.

Dominion Resources Services (Dominion Services) and affiliates provide certain administrative and technical services to the Company. The Company provides certain services to affiliates, including technical services to other Dominion subsidiaries. The cost of these services is as follows:


	Year Ended December 31,
	2004		2003		2002
(millions)
Services provided to the Company by Dominion Services	$	168	$	159	$	166
Services provided by the Company to affiliates		9		10		8
Services provided to the Company by affiliates		2		2		1

Transactions with Dominion

The Company and its subsidiaries have borrowed funds from Dominion. At December 31, 2004 and 2003, the outstanding borrowings, net of repayments, under the Dominion money pool totaled $1.0 billion and $901 million, respectively, and a short-term demand note totaled $163 million and $126 million, respectively. Interest charges related to these borrowings incurred by the Company were $15 million in 2004 and $13 million in 2003. The consolidated Dominion money pool was formed in March 2003 as the existing CNG money pool was terminated pursuant to a SEC order. Outstanding balances under the CNG money pool and certain borrowings pursuant to the short-term demand note from Dominion were converted to the Dominion money pool. In September 2003, Dominion made a $600 million equity contribution to the Company that reduced the money pool borrowings.

In connection with the reduction in amounts payable to Dominion, the Company recognized $41 million, $6 million and $32 million of additional paid-in capital in 2004, 2003 and 2002, respectively.

Other Related Party Transactions

Upon adoption of FIN 46R for its interests in special purpose entities on December 31, 2003, the Company ceased to consolidate the Dominion CNG Capital Trust I, a finance subsidiary of the Company. The junior subordinated notes issued by the Company and held by the trust are reported as long-term debt. The Company reported $16 million each of interest expense on the junior subordinated notes payable to affiliated trust in 2004 and distributions of mandatorily redeemable trust preferred securities in 2003.

Equity Method Investments

At December 31, 2004 and 2003, the Company’s equity method investments totaled $204 million and $243 million, respectively. The Company’s equity method investments are reported in investments in affiliates, with the exception of approximately $2 million in 2004 and $44 million in 2003, which are classified as part of assets held for sale in other current assets. Equity earnings on these investments totaled $14 million in 2004, $21 million in 2003 and $23 million in 2002. The Company received dividends from these investments of $9 million, $7 million and $7 million in 2004, 2003, and 2002, respectively. The equity earnings are reported in other income (loss) in the Consolidated Statements of Income.

2004 / Page 44

Notes to Consolidated Financial Statements, Continued

Note 23. Operating Segments

The Company is organized primarily on the basis of products and services sold in the United States. The Company manages its operations through the following segments:

Energy includes the Company’s natural gas transmission pipeline and storage system, certain gas production operations, an LNG import and storage facility and producer services operations that include aggregation of gas supply and related wholesale activities.

Delivery includes the Company’s regulated gas distribution systems and customer service operations and the Company’s nonregulated retail energy marketing activities.

Exploration & Production (E&P) includes the Company’s gas and oil exploration, development and production operations. Operations are located in several major producing basins in the lower 48 states, including the outer continental shelf and deepwater areas of the Gulf of Mexico.

Corporate and Other includes the Company’s corporate and other functions, including the activities of CNGI, the Company’s power generating facility and other minor subsidiaries. In addition, the contribution to net income by the Company’s primary operating segments is determined based on a measure of profit that executive management believes represents the segments’ core earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by executive management in assessing the segment’s performance or allocating resources among the segments. These specific items are reported in Corporate and Other and include:

•

2004 losses related to the discontinuance of hedge accounting for certain oil hedges and subsequent changes in the fair value of those hedges in the third quarter;

•

2003 cumulative effect of changes in accounting principles; and

•

2003 severance costs associated with workforce reductions.

In 2002, there were no specific items attributable to the Company’s primary operating segments reported in the Corporate and Other segment.

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

2004 / Page 45

Notes to Consolidated Financial Statements, Continued

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


	Energy		Delivery		E&P			Corporate and Other			Adjustments & Eliminations			Consolidated Total
(millions)
2004
Total revenue from external and affiliated customers	$	1,995	$	2,629	$	1,896		$	44		$	—		$	6,564
Intersegment revenue		214		63		132			—			(409	)		—
Total operating revenue		2,209		2,692		2,028			44			(409	)		6,564
Interest and related charges		31		46		76			202			(183	)		172
Interest income		1		7		2			181			(183	)		8
Depreciation, depletion and amortization		80		82		459			6			—			627
Equity in earnings of equity method investees		12		3		(2	)		1			—			14
Income tax expense (benefit)		143		84		263			(8	)		—			482
Net income (loss)		228		184		520			(65	)		—			867
Investment in equity method investees		93		13		33			65			—			204
Capital expenditures		234		132		1,180			—			—			1,546
Total assets (at December 31)		2,866		4,127		9,794			4,743			(4,808	)		16,722
2003
Total revenue from external customers	$	1,574	$	2,200	$	1,479		$	60		$	—		$	5,313
Intersegment revenue		216		47		121			—			(384	)		—
Total operating revenue		1,790		2,247		1,600			60			(384	)		5,313
Interest and related charges		28		42		68			199			(184	)		153
Interest income		1		6		2			182			(184	)		7
Depreciation, depletion and amortization		70		78		433			—			—			581
Equity in earnings of equity method investees		14		1		5			1			—			21
Income tax expense (benefit)		141		78		175			(22	)		—			372
Net income (loss)		213		177		317			(69	)		—			638
Investment in equity method investees		84		10		44			105			—			243
Capital expenditures		232		135		1,177			—			—			1,544
Total assets (at December 31)		2,659		3,854		7,884			4,643			(4,421	)		14,619
2002
Total revenue from external customers	$	946	$	1,673	$	1,255		$	26		$	—		$	3,900
Intersegment revenue		136		7		65			—			(208	)		—
Total operating revenue		1,082		1,680		1,320			26			(208	)		3,900
Interest and related charges		20		45		75			209			(194	)		155
Interest income		1		4		1			193			(194	)		5
Depreciation, depletion and amortization		67		77		410			—			—			554
Equity in earnings of equity method investees		11		—		5			7			—			23
Income tax expense (benefit)		122		71		133			(14	)		—			312
Net income		196		174		256			12			—			638

As of December 31, 2004 and 2003, less than 1% of the Company’s total long-lived assets were associated with international operations. For the years ended December 31, 2004, 2003 and 2002, less than 1% of the Company’s operating revenues were associated with international operations.

2004 / Page 46

Notes to Consolidated Financial Statements, Continued

Note 24. Condensed Consolidating Financial Information

The Company has fully and unconditionally guaranteed $200 million of senior notes issued by its wholly-owned subsidiary, Dominion Oklahoma Texas Exploration and Production, Inc. (DOTEPI). In the event of a default by this subsidiary, the Company would be obligated to repay such amounts. Condensed consolidating financial information for the Company, DOTEPI and the Company’s other subsidiaries are presented below:

Condensed Consolidating Statement of Income Information


Year Ended December 31, 2004	CNG (Parent Company)			DOTEPI		Other Subsidiaries		Adjustments & Eliminations			Consolidated
Operating revenue	$	—		$	630	$	6,434	$	(500	)	$	6,564
Operating expenses		1			350		5,222		(475	)		5,098
Income from operations		(1	)		280		1,212		(25	)		1,466
Other income		187			—		51		(183	)		55
Interest and related charges		197			42		117		(184	)		172
Income before income taxes		(11	)		238		1,146		(24	)		1,349
Income tax expense (benefit)		(5	)		72		425		(10	)		482
Equity in earnings of subsidiaries		873			—		—		(873	)		—
Net income	$	867		$	166	$	721	$	(887	)	$	867


Year Ended December 31, 2003	CNG (Parent Company)			DOTEPI		Other Subsidiaries			Adjustments & Eliminations			Consolidated
Operating revenue	$	—		$	610	$	5,180		$	(477	)	$	5,313
Operating expenses		(1	)		371		4,174			(437	)		4,107
Income from operations		1			239		1,006			(40	)		1,206
Other income (loss)		189			—		(21	)		(200	)		(32	)
Interest and related charges		199			33		122			(201	)		153
Income before income taxes		(9	)		206		863			(39	)		1,021
Income tax expense (benefit)		(12	)		71		327			(14	)		372
Income before cumulative effect of changes in accounting principles		3			135		536			(25	)		649
Equity in earnings of subsidiaries		635			—		—			(635	)		—
Cumulative effect of changes in accounting principles		—			1		(12	)		—			(11	)
Net income	$	638		$	136	$	524		$	(660	)	$	638


Year Ended December 31, 2002	CNG (Parent Company)			DOTEPI		Other Subsidiaries		Adjustments & Eliminations			Consolidated
Operating revenue	$	—		$	502	$	3,741	$	(343	)	$	3,900
Operating expenses		(13	)		320		2,817		(294	)		2,830
Income from operations		13			182		924		(49	)		1,070
Other income		191			4		54		(214	)		35
Interest and related charges		212			41		117		(215	)		155
Income before income taxes		(8	)		145		861		(48	)		950
Income tax expense (benefit)		(11	)		56		286		(19	)		312
Equity in earnings of subsidiaries		635			—		—		(635	)		—
Net income	$	638		$	89	$	575	$	(664	)	$	638

2004 / Page 47

Notes to Consolidated Financial Statements, Continued

Condensed Consolidating Balance Sheet Information

At December 31, 2004

CNG (Parent
Company)

DOTEPI

Other
Subsidiaries

Adjustments &
Eliminations

Consolidated

Assets

Current assets

1,866

341

3,047

(2,625

)

2,629

Investment in affiliates

3,891

—

141

(3,828

)

204

Loans to affiliates

2,202

—

(2,202

)

—

Property, plant, and equipment, net

—

3,619

7,506

(75

)

11,050

Deferred charges and other assets

225

532

2,450

(368

)

2,839

Total assets

8,184

4,492

13,144

(9,098

)

16,722

Liabilities & Shareholder’s Equity

Current liabilities

379

1,047

5,408

(2,622

)

4,212

Long-term debt

3,014

206

234

—

3,454

Notes payable to affiliates

206

1,089

1,113

(2,202

)

206

Deferred credits and other liabilities

105

1,093

3,582

(410

)

4,370

Common shareholder’s equity

4,480

1,057

2,807

(3,864

)

4,480

Total liabilities and shareholder’s equity

8,184

4,492

13,144

(9,098

)

16,722


At December 31, 2003	CNG (Parent Company)		DOTEPI		Other Subsidiaries		Adjustments & Eliminations			Consolidated
Assets
Current assets	$	2,027	$	196	$	2,658	$	(2,844	)	$	2,037
Investment in affiliates		3,768		—		183		(3,748	)		203
Loans to affiliates		2,027		—		—		(2,027	)		—
Property, plant and equipment, net		—		3,261		6,968		(49	)		10,180
Deferred charges and other assets		127		535		1,607		(70	)		2,199
Total assets	$	7,949	$	3,992	$	11,416	$	(8,738	)	$	14,619
Liabilities & Shareholder’s Equity
Current liabilities	$	608	$	1,081	$	4,734	$	(2,880	)	$	3,543
Long-term debt		2,768		211		234		—			3,213
Notes payable to affiliates		206		1,089		939		(2,028	)		206
Deferred credits and other liabilities		2		701		2,693		(104	)		3,292
Common shareholder’s equity		4,365		910		2,816		(3,726	)		4,365
Total liabilities and shareholder’s equity	$	7,949	$	3,992	$	11,416	$	(8,738	)	$	14,619

Condensed Consolidating Statement of Cash Flow Information


Year Ended December 31, 2004	CNG (Parent Company)			DOTEPI			Other Subsidiaries			Adjustments & Eliminations			Consolidated
Net cash provided by operating activities	$	448		$	175		$	1,476		$	(481	)	$	1,618
Net cash provided by (used in) investing activities		188			(374	)		(829	)		(71	)		(1,086	)
Net cash provided by (used in) financing activities		(636	)		192			(660	)		552			(552	)
Year Ended December 31, 2003	CNG (Parent Company)			DOTEPI			Other Subsidiaries			Adjustments & Eliminations			Consolidated
Net cash provided by operating activities	$	365		$	484		$	470		$	(404	)	$	915
Net cash provided by (used in) investing activities		240			(299	)		(961	)		(300	)		(1,320	)
Net cash provided by (used in) financing activities		(605	)		(176	)		497			706			422
Year Ended December 31, 2002	CNG (Parent Company)			DOTEPI			Other Subsidiaries			Adjustments & Eliminations			Consolidated
Net cash provided by operating activities	$	404		$	327		$	757		$	(352	)	$	1,136
Net cash provided by (used in) investing activities		(1,103	)		(558	)		(1,414	)		1,220			(1,855	)
Net cash provided by (used in) financing activities		699			238			622			(871	)		688

2004 / Page 48

Notes to Consolidated Financial Statements, Continued

Note 25. 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 follow:


	At December 31,
	2004		2003
(millions)
Capitalized costs:
Proved properties	$	9,346	$	8,077
Unproved properties		1,948		2,040
		11,294		10,117
Accumulated depletion:
Proved properties		3,859		3,239
Unproved properties		291		299
		4,150		3,538
Net capitalized costs	$	7,144	$	6,579

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
(millions)
Property acquisition costs:
Proved properties	$	19	$	178	$	243
Unproved properties		101		124		168
		120		302		411
Exploration costs		197		268		258
Development costs⁽¹⁾		811		570		630
Total	$	1,128	$	1,140	$	1,299

(1)

Development costs incurred for proved undeveloped reserves were $162 million, $177 million and $205 million for 2004, 2003 and 2002, respectively.

Results of Operations

The Company cautions that the following standardized disclosures required by the FASB do not represent the results of operations based on its historical financial statements. In addition to requiring different determinations of revenue and costs, the disclosures exclude the impact of interest expense and corporate overhead.


	Year Ended December 31,
	2004		2003		2002
(millions)
Revenue (net of royalties) from:
Sales to nonaffiliated companies	$	1,169	$	1,207	$	1,058
Transfers to other operations		167		159		98
Total		1,336		1,366		1,156
Less:
Production (lifting) costs		259		252		171
Depreciation, depletion and amortization		457		425		416
Income tax expense		243		248		195
Results of operations	$	377	$	441	$	374

2004 / Page 49

Notes to Consolidated Financial Statements, Continued

Company-Owned Reserves

Estimated net quantities of proved gas and oil (including condensate) reserves in the United States at December 31, 2002 through 2004 and changes in the reserves during those years are shown in the two tables which follow.


	2004			2003			2002
(billion cubic feet)
Proved developed and undeveloped reserves—Gas
At January 1		4,112			3,662			2,796
Changes in reserves:
Extensions, discoveries and other additions		327			732			634
Revisions of previous estimates		200			2			140
Production		(278	)		(292	)		(286	)
Purchases of gas in place		10			131			379
Sales of gas in place		(85	)		(123	)		(1	)
At December 31		4,286			4,112			3,662
Proved developed reserves—Gas
At January 1		2,971			2,869			2,347
At December 31		3,131			2,971			2,869

	2004			2003			2002
(thousands of barrels)
Proved developed and undeveloped reserves—Oil
At January 1		135,717			138,328			115,653
Changes in reserves:
Extensions, discoveries and other additions		7,546			7,818			24,273
Revisions of previous estimates		(5,616	)		1,374			4,042
Production		(8,772	)		(7,574	)		(8,537	)
Purchases of oil in place		666			380			2,928
Sales of oil in place		(818	)		(4,609	)		(31	)
At December 31		128,723			135,717			138,328
Proved developed reserves—Oil
At January 1		42,150			47,290			46,138
At December 31		87,181			42,150			47,290
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 the Company.
	2004			2003			2002
(millions)
Future cash inflows⁽¹⁾	$	32,115		$	29,049		$	21,990
Less:
Future development costs⁽²⁾		1,436			1,325			958
Future production costs		4,676			4,198			2,353
Future income tax expense		8,856			7,615			5,999
Future net cash flows		17,147			15,911			12,680
Less annual discount (10% a year)		9,286			8,632			6,514
Standardized measure of discounted future net cash flows	$	7,861		$	7,279		$	6,166

(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 to be $423 million, $197 million and $230 million for 2005, 2006 and 2007, respectively.

2004 / Page 50

Notes to Consolidated Financial Statements, Continued

In the 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 pre-tax net cash flows, less the tax basis of the properties 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 the Company’s proved reserves. The Company 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 is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations and no value may be assigned to probable or possible reserves.

The following tabulation is a 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 at January 1	$	7,279		$	6,166		$	2,328
Changes in the year resulting from:
Sales and transfers of gas and oil produced during the year, less production costs		(1,647	)		(1,460	)		(893	)
Prices and production and development costs related to future production		1,327			511			2,426
Extensions, discoveries and other additions, less production and development costs		948			1,677			1,685
Previously estimated development costs incurred during the year		162			177			205
Revisions of previous quantity estimates		(102	)		(522	)		(120	)
Accretion of discount		1,075			908			326
Income taxes		(551	)		(554	)		(1,984	)
Other purchases and sales of proved reserves in place, net		(386	)		72			787
Other (principally timing of production)		(244	)		304			1,406
Standardized measure of discounted future net cash flows at December 31	$	7,861		$	7,279		$	6,166

2004 / Page 51

Note 26. Quarterly Financial Data (Unaudited)

A summary of the quarterly results of operations for the years ended December 31, 2004 and 2003 follows. Amounts shown reflect all adjustments, consisting of only normal recurring accruals, necessary in the opinion of management for a fair statement of the results for the interim periods.

Because a major portion of the gas sold or transported by the Company’s distribution and transmission operations is ultimately used for space heating, both revenue and earnings are subject to seasonal fluctuations. Seasonal fluctuations may be further influenced by the timing of rate relief granted under regulation to compensate for the increased cost of providing service to customers.


	2004								2003
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		First Quarter			Second Quarter		Third Quarter		Fourth Quarter
(millions)
Operating revenue	$	2,078	$	1,301	$	1,248	$	1,937	$	1,724		$	1,087	$	1,022	$	1,480
Income from operations		495		326		189		456		429			212		203		362
Income before cumulative effect of changes in accounting principles		311		182		100		274		252			103		115		179
Cumulative effect of changes in accounting principles		—		—		—		—		(5	)		—		—		(6	)
Net income	$	311	$	182	$	100	$	274	$	247		$	103	$	115	$	173

The Company’s 2004 results include the impact of the following significant items:

•

First quarter results reflect an $18 million benefit for an adjustment to the carrying amount of CNGI’s investment in an Australian pipeline business based on an agreement, whereby a portion of the pipeline assets was sold for an amount in excess of what the Company had previously estimated;

•

Second quarter results reflect an increase in an income tax valuation allowance related to CNGI investments, partially offset by an $8 million gain on the sale of a portion of CNGI’s investment in an Australian pipeline business in June 2004;

•

Third quarter results include $61 million of after-tax losses related to the discontinuance of hedge accounting for certain oil hedges, resulting from an interruption in oil production in the Gulf of Mexico caused by Hurricane Ivan, and subsequent changes in the fair value of those hedges in the third quarter; and

•

Fourth quarter results include a $61 million after-tax benefit due to the recognition of business interruption insurance revenue associated with the recovery of delayed gas and oil production due to Hurricane Ivan.

The Company’s 2003 results include the impact of the following significant items:

•

Second quarter results include $25 million of after-tax impairment losses related to CNGI’s investments in the Australian pipeline business and a small generation facility in Kauai, Hawaii; and

•

Fourth quarter results include $40 million of after-tax impairment losses related to CNGI’s investments in the Australian pipeline business and a small generation facility in Kauai, Hawaii that was sold in December 2003.

2004 / Page 52

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

None.

Item 9A. Controls and Procedures

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

On December 31, 2003, the Company adopted FIN 46R for its interests in special purpose entities referred to as SPEs. As a result, the Company has included in its consolidated financial statements those SPEs described in Note 3 to the Consolidated Financial Statements. The Consolidated Balance Sheet as of December 31, 2004 reflects $215 million of net property, plant and equipment and deferred charges and $234 million of related debt attributable to the SPEs. As these SPEs are owned by unrelated parties, the Company does not have the authority to dictate or modify, and therefore cannot assess, the disclosure controls and procedures in place at these entities.

Item 9B. Other Information

None.

2004 / Page 53

Part III

Item 10. Directors and Executive Officers of the Registrant

Omitted pursuant to General Instruction I.(2)(c).

Item 11. Executive Compensation

Omitted pursuant to General Instruction I.(2)(c).

Item 12. Security Ownership of Certain Beneficial Owners and Management

Omitted pursuant to General Instruction I.(2)(c).

Item 13. Certain Relationships and Related Transactions

Omitted pursuant to General Instruction I.(2)(c).

Item 14. Principal Accountant Fees and Services

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


Type of Fees	2004		2003
(thousands)
Audit fees	$	1,331	$	1,238
Audit-related		275		221
Tax fees		—		—
All other fees		—		—
All other fees	$	1,606	$	1,459

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

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

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

2004 / Page 54

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 20.

2. Financial Statement Schedules


		Page
Report of Independent Registered Public Accounting Firm		57
Schedule I—Condensed Financial Information of Registrant		58

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

3. Exhibits



3.1 —		Certificate of Incorporation of Consolidated Natural Gas Company (Exhibit (3A)(i) to Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference).

3.2 —		Certificate of Amendment of Certificate of Incorporation, dated January 28, 2000 (Exhibit (3A)(ii) to Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference).

3.3 —		Bylaws as in effect on December 15, 2000 (Exhibit 3B to Form 10-K for the fiscal year ended December 31, 2000, File No. 1-3196, incorporated by reference).

4.1 —		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 (4A)(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, Form 10-Q for the quarter ended September 30, 2003, File No. 1-3196, incorporated by reference).

4.2 —		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 (4 A)(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 7³/8% Debentures Due April 1, 2005); Securities Resolution No. 2 effective 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, 2026); 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 6⁵/8% 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, 2010); 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) .

4.3 —		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, Form 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).

2004 / Page 55



4.4 —		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).

4.5 —		Indenture, dated as of June 15, 1994, between Louis Dreyfus Natural Gas Corp., Dominion Oklahoma Texas Exploration and Production, Inc. and The Bank of New York (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 Supplemental Indenture, dated as of November 1, 2001 (Exhibit 4.7, Form 10-Q for the quarter ended September 30, 2001, incorporated by reference).

4.6 —		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, 2001, 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-Q for the quarter ended September 30, 2001, incorporated by reference).

10.1 —		$1,500,000,000 Three Year Credit Agreement among Dominion Resources, Inc., Virginia Electric and Power Company, Consolidated Natural Gas Company and JPMorgan Chase Bank, as Administrative Agent for the Lenders, dated May 27, 2004 (Exhibit 10.3, Form 10-Q for the quarter ended March 31, 2004, File No. 1-8489, incorporated by reference).

10.2 —		$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-Q for the quarter ended September 30, 2004, File No. 1-8489, incorporated by reference).

10.3 —		$750,000,000 Three-Year Credit Agreement among Dominion Resources, Inc., Virginia Electric and Power Company, Consolidated Natural Gas Company and JPMorgan Chase Bank, as Administrative Agent for the Lenders, dated as of May 30, 2002 (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2003, File No. 1-8489, incorporated by reference).

12 —		Ratio of earnings to fixed charges (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).

2004 / Page 56

CONSOLIDATED NATURAL GAS CO/VA 10-K