SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

____________

FORM 10-Q
____________

(Mark one)

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2004

or

____ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Commission File Number 1-3196

CONSOLIDATED NATURAL GAS COMPANY

(Exact name of registrant as specified in its charter)

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

120 Tredegar Street RICHMOND, VIRGINIA (Address of principal executive offices)	23219 (Zip Code)

(804) 819-2000 (Registrant's telephone number)

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~~

Yes X No

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

At ~~October~~June 3130, ~~2003~~2004, the latest practicable date for determination, 100 shares of common stock, without par value, of the registrant were outstanding.

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

PAGE 2

CONSOLIDATED NATURAL GAS COMPANY

INDEX

		Page Number	~~Page Number~~
PART I. Financial Information
Item 1.	Consolidated Financial Statements
Item 1	Consolidated Financial Statements
	Consolidated Statements of Income - Three and Nine Months Ended September 30, 2003 and 2002			3
	Consolidated Statements of Income - Three and Six Months Ended June 30, 2004 and 2003	3
	Consolidated Balance Sheets - September 30, 2003 and December 31, 2002			4
	Consolidated Balance Sheets - June 30, 2004 and December 31, 2003	4
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2003 and 2002			6
	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2004 and 2003	6
	Notes to Consolidated Financial Statements	7		7
Item 2.	Management's Discussion and Analysis of Results of Operations			18
Item 2	Management's Discussion and Analysis of Results of Operations	17
Item 4.	Controls and Procedures			28
Item 4	Controls and Procedures	30
	PART II. Other Information
Item 1.	Legal Proceedings			29
Item 1	Legal Proceedings	31
Item 6.	Exhibits and Reports on Form 8-K			29
Item 5	Other Items	31
Item 6	Exhibits and Reports on Form 8-K	31

PAGE 3

CONSOLIDATED NATURAL GAS COMPANY PART I. FINANCIAL INFORMATION ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

~~PART I. FINANCIAL INFORMATION~~ ~~ITEM 1.~~ CONSOLIDATED ~~FINANCIAL~~ STATEMENTS ~~CONSOLIDATED~~ ~~STATEMENTS~~ OF INCOME (Unaudited)

	Three Months Ended September 30,		Nine Months Ended September 30,
	Three Months Ended June 30,		Six Months Ended June 30,
	2003	2002	2003	2002
	2004	2003	2004	2003
	(Millions)
	(millions)
Operating Revenue	~~$1,022~~	~~$750~~	~~$3,833~~	~~$2,670~~
External customers	$1,011	$916	$2,781	$2,527
Affiliated customers	290	171	598	284
Total operating revenue	1,301	1,087	3,379	2,811
Operating Expenses
Purchased gas, net	~~353~~	~~169~~	~~1,547~~	~~795~~
Electric fuel and energy purchases	60	41	142	67
External suppliers	371	235	1,285	899
Liquids, pipeline capacity and other purchases	41	43	137	121
Affiliated suppliers	129	170	279	295
Other operations and maintenance	168	141	546	434
Electric fuel and energy purchases
Depreciation, depletion and amortization	152	143	442	415
External suppliers	35	20	77	55
Other taxes	45	36	175	137
Affiliated suppliers	53	17	91	27
Total operating expenses	819	573	2,989	1,969
Liquids, pipeline capacity and other purchases	58	43	109	96
Income from operations	203	177	844	701
Other operations and maintenance
Other income	10	9	2	28
External	83	153	193	294
Affiliated	38	39	80	84
Depreciation, depletion and amortization	154	150	308	290
Other taxes	54	48	136	130
Total operating expenses	975	875	2,558	2,170
Income from operations	326	212	821	641
Other income (expense)	11	(9)	40	(8)
Interest and related charges:
Interest expense-mandatorily redeemable trust preferred securities	4	-	4	-
Interest expense-junior subordinated notes payable to affiliated trust	4	-	8	-
Interest expense-other	32	31	103	100
Interest expense - other	37	36	75	71
Distribution-preferred securities of subsidiary trust	-	4	8	15
Distributions-mandatorily redeemable trust preferred securities	-	4	-	8
Total interest and related charges	3641	3540	~~115~~83	~~115~~79
Income before income taxes	~~177~~296	~~151~~163	~~731~~778	~~614~~554
Income taxes	62	38	261	196
Income tax expense	114	60	285	199
Income before cumulative effect of a change in accounting principle	~~115~~182	~~113~~103	~~470~~493	~~418~~355
Cumulative effect of a change in accounting principle (net of income taxes of $3)	-	-	~~(5)~~-	-(5)
Net Income	$ 115	$113	$ 465	$ 418
Net income	$ 182	$ 103	$ 493	$ 350

~~________________~~____________

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

PAGE 4

CONSOLIDATED NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)

	September 30, 2003	December 31, 2002(1)
	June 30, 2004	December 31, 2003(1)
	(Millions)
	(millions)
ASSETS
Current Assets
Cash and cash equivalents	$ 5729	$ 2239
Customer accounts receivable (net of allowance of $42 and $50)	503	662
Customer accounts receivable (net of allowance of $30 in 2004 and $37 in 2003)	691	795
Other accounts receivable	6251	2545
Receivables from affiliates	267	96
Receivables due from affiliates	412	340
Inventories	~~322~~150	~~115~~238
Derivative assets	116	181
Prepayments	35	56
Assets held for sale	103	145
Derivative assets	186	106
Prepayments	38	113
Other	272	296
Other	218	198
Total current assets	1,826	1,915
Total current assets	1,686	1,557
Investments
Investments	267	245
Investment in affiliates	212	203
Other	83	79
Total investments	295	282
Property, Plant and Equipment
Property, plant and equipment	1516,~~267~~458	1415,~~119~~854
Accumulated depreciation, depletion and amortization	(5,~~807~~932)	(5,~~552~~674)
Total property, plant and equipment, net	9,460	8,567
Net property, plant and equipment	10,526	10,180
Deferred Charges and Other Assets
Goodwill, net	~~626~~623	~~625~~626
Prepaid pension cost	838	738
Regulatory assets	341	328
Other	570	489
Prepaid pension cost	928	872
Total deferred charges and other assets	2,034	1,852
Derivative assets	300	84
Total assets	$13,447	$12,221
Other	210	210
Total deferred charges and other assets	2,402	2,120
Total assets	$15,049	$14,497

________________

^{The accompanying notes are an integral part of the Consolidated Financial Statements.
(1)}The Consolidated Balance Sheet at December 31, 2003 has been derived from the audited Consolidated Financial Statements at that date.

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

PAGE 5

CONSOLIDATED NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS-(Continued)

(Unaudited)

	September 30, 2003	December 31, 2002(1)
	June 30, 2004	December 31, 2003(1)
	(Millions)
	(millions)
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities
Securities due within one year	$ 88555		$ ~~150~~501
Short-term debt	~~200~~-		~~397~~151
Accounts payable, trade	~~615~~630		~~601~~655
Payables to affiliates	~~112~~122		~~102~~118
Affiliated current borrowings	~~673~~645		~~563~~1,027
Accrued interest, payroll and taxes	~~238~~241		~~193~~214
Derivative liabilities	~~470~~991		~~442~~620
Other	~~385~~468		~~275~~278
Total current liabilities	23,~~781~~652		23,~~723~~564
Long-Term Debt
Company obligated mandatorily redeemable preferred securities of subsidiary trust(2)	200		-
Long-term debt	3,052		3,213
Other long-term debt	3,207		3,309
Junior subordinated notes payable to affiliated trust	206		206
Total long-term debt	3,~~407~~258		3,~~309~~419
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits	1,~~723~~858		1,~~662~~760
Derivative liabilities	625		382
Asset retirement obligations	245		240
Other	516		129
Derivative liabilities	1,057		669
Total deferred credits and other liabilities	2,864		2,173
Regulatory liabilities	216		212
Total liabilities	9,052		8,205
Other	458		268
Commitments and Contingencies (see Note 12)
Total deferred credits and other liabilities	3,834		3,149
Minority Interest	9		7
Total liabilities	10,744		10,132
Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust(2)	-		200
Commitments and Contingencies (see Note 13)
Common Shareholder's Equity
Common stock-no par value, 100 shares authorized and outstanding	1,816		1,816
Other paid-in capital	2,~~472~~478		12,~~871~~478
Accumulated other comprehensive loss	(471)		(298)
Retained earnings	830		608
Retained earnings	569		420
Accumulated other comprehensive loss	(819)		(537)
Total common shareholder's equity	4,~~386~~305		34,~~809~~365
Total liabilities and shareholder's equity	$1315,~~447~~049		$1214,~~221~~497

________________

~~(2)~~ The accompanying notes are an integral part of the Consolidated Financial Statements.

PAGE 6

CONSOLIDATED NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Nine Months Ended September 30,
	Six Months Ended June 30,
	2003	2002
	2004	2003
	(Millions)
	(millions)
Operating Activities
Net income	$ ~~465~~493	$ ~~418~~350
Adjustments to reconcile net income to net cash from operating activities:
Adjustments to reconcile net income to net cash provided by operating activities:
Cumulative effect of changes in accounting principle, net of income taxes	5	-
Depreciation, depletion and amortization	308	290
Depreciation, depletion and amortization	442	415
Deferred income taxes and investment tax credits, net	214	117
Deferred income taxes and investment tax credits, net	146	170
Valuation adjustment on CNG International assets	(18)	-
Cumulative effect of a change in accounting principle, net of income taxes	-	5
Changes in:
Accounts receivable	~~122~~98	~~230~~56
Affiliated accounts receivable and payable	(161)	(146)
Affiliated receivables and payables	(68)	(134)
Inventories	~~(207)~~88	(95)
Prepayments	7521	~~121~~51
Margin deposit assets and liabilities	3714	(~~112~~121)
Deferred purchased gas costs, net	~~(77)~~1	(61129)
Accounts payable, trade	14(25)	(9720)
Accrued interest, payroll and taxes	4727	3517
Other, net	(65)	(12)
Other operating assets and liabilities	(62)	142
Net cash provided by operating activities	~~843~~1,091	~~952~~619
Investing Activities
Plant construction and other property additions	(285)	(226)
Additions to gas and oil properties, including acquisitions	(543)	(475)
Additions to gas and oil properties, including acquisitions	(855)	(1,001)
Proceeds from sales of gas and oil properties	413	-
Proceeds from sales of gas and oil properties	290	-
Plant construction and other property additions	(132)	(197)
Acquisition of business	-	(216)
Other	47	(1)
Other	(4)	57
Net cash used in investing activities	(215)	(673)
Net cash used in investing activities	(854)	(1,386)
Financing Activities
Short-term borrowings from parent, net	710	725
Repayment of short-term debt, net	(151)	(380)
Repayment of short-term debt, net	(197)	(53)
Issuance (repayment) of affiliated current borrowings, net	(382)	702
Repayment of long-term debt	(~~151~~88)	~~(6)~~-
Dividends paid	(316)	(261)
Common stock dividend payments	(271)	(245)
Other	-6	~~(3)~~-
Net cash provided by financing activities	46	402
Net cash (used in) provided by financing activities	(886)	77
Increase (decrease) in cash and cash equivalents	35(10)	~~(32)~~23
Cash and cash equivalents at beginning of period	2239	5322
Cash and cash equivalents at end of period	$ 5729	$ 2145
Supplemental Cash Flow Information
Noncash transaction from financing activities:
Conversion of short-term borrowings from parent to paid-in capital	$ 600	$ 650

________________

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

PAGE 7

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, ~~manages~~through its ~~daily~~subsidiaries, ~~operations~~operates ~~through~~in ~~three~~all ~~primary~~phases ~~operating~~of ~~segments:~~the ~~Delivery~~natural gas business, ~~Energy~~explores for and ~~Exploration~~produces &gas ~~Production~~and oil and provides a variety of energy marketing services. InIts ~~addition~~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 1.4 million residential and commercial customer accounts in the Northeast and Midwest. The Company ~~reports~~operates ~~its~~an ~~corporate~~interstate gas transmission pipeline system in the Midwest, the Mid-Atlantic states and ~~other~~the ~~functions~~Northeast asand a ~~segment~~liquefied natural gas import and storage facility in Maryland. ~~Assets~~The ~~remain~~Company's ~~wholly-owned~~producer byservices operations involve the aggregation of natural gas supply and related wholesale activities. The Company's ~~legal~~exploration ~~subsidiaries~~and production operations are located in several major gas and oil producing basins in the United States, both onshore and offshore.

The ~~term "the~~ Company" ismanages ~~used~~its ~~throughout~~daily ~~this~~operations ~~report~~through ~~and,~~three ~~depending~~primary onoperating ~~the~~segments: ~~context~~Energy, ofDelivery ~~its~~and ~~use,~~Exploration ~~may~~& ~~represent~~Production. ~~any~~In ofaddition, the ~~following:~~Company ~~the~~reports ~~legal~~its ~~entity;~~corporate ~~Consolidated~~functions ~~Natural~~as ~~Gas~~a ~~Company;~~segment. ~~one~~Assets ofremain ~~Consolidated~~wholly-owned ~~Natural~~by ~~Gas~~the Company's ~~consolidated~~legal subsidiaries~~; or the entirety of Consolidated Natural Gas Company and its consolidated subsidiaries~~.

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

As permitted by the rules and regulations of the Securities and Exchange Commission (SEC), the accompanying unaudited Consolidated Financial Statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles). These unaudited Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes in the Company's Annual Report on Form 10-K for the year ended December 31, ~~2002~~2003 asand ~~well as~~ the ~~quarterly~~Quarterly ~~reports~~Report ~~for~~on ~~previous~~Form ~~interim~~10-Q ~~periods~~for ofthe ~~2003~~quarter ~~filed~~ended onMarch ~~Form~~31, ~~10-Q~~2004.

In the opinion of the Company's management, the accompanying unaudited Consolidated Financial Statements contain all adjustments, including normal recurring accruals, necessary to present fairly the Company's financial position as of ~~September~~June 30, ~~2003~~2004, its results of operations for the three and ~~nine~~six months ended June 30, 2004 and 2003, and its cash flows for the ~~nine~~six months ended ~~September~~June 30, ~~2003~~2004 and ~~2002~~2003.

The ~~accompanying~~Company ~~unaudited~~makes ~~Consolidated~~certain ~~Financial~~estimates ~~Statements~~and ~~represent~~assumptions ~~the~~in ~~accounts~~preparing ofits ~~the~~Consolidated ~~Company,~~Financial ~~with~~Statements ~~intercompany transactions eliminated~~ in ~~consolidation.~~accordance ~~The~~with ~~Company~~generally ~~follows~~accepted ~~the~~accounting ~~equity~~principles. ~~method~~These ofestimates ~~accounting~~and ~~for~~assumptions ~~investments~~affect ~~with~~the ~~less~~reported ~~than~~amounts orof ~~equal~~assets toand aliabilities, 50the ~~percent~~disclosure ~~interest~~of incontingent ~~partnerships~~assets orand ~~corporate~~liabilities ~~joint~~at ~~ventures when~~ the ~~Company~~date isof ~~able~~the tofinancial ~~exercise~~statements ~~significant~~and ~~influence~~the ~~over~~reported ~~the~~amounts ~~financial~~of revenue and ~~operating~~expenses ~~policies~~for of the ~~investee~~periods presented. ~~For~~Actual ~~all~~results ~~other~~may ~~investments,~~differ ~~the~~from ~~cost~~those ~~method is applied~~estimates.

The accompanying unaudited Consolidated Financial Statements ~~reflect~~include, ~~certain~~after ~~estimates~~eliminating ~~and~~intercompany ~~assumptions~~transactions ~~made by management in accordance with generally accepted accounting principles. These estimates~~ and ~~assumptions~~balances, ~~affect~~ the ~~reported~~accounts ~~amounts~~ of ~~assets and liabilities,~~ the ~~disclosure~~Company ~~of contingent assets~~ and ~~liabilities~~all atmajority-owned ~~the~~subsidiaries, ~~date~~and ofthose ~~the~~variable ~~Consolidated~~interest ~~Financial~~entities ~~Statements~~where ~~and~~ the ~~reported~~Company ~~amounts~~is ~~of revenue and expenses for~~ the ~~periods~~primary ~~presented~~beneficiary. ~~Actual results may differ from those estimates.~~

The Company reports certain contracts and instruments at fair value in accordance with generally accepted accounting principles. Market pricing and indicative price information from external sources are used to measure fair value when available. In the absence of this information, the Company estimates fair value based on near-term and historical price information and statistical methods. For individual contracts, the use of differing assumptions could have a material effect on the contract's estimated fair value. See Note 2 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2003 for a more detailed discussion of the Company's estimation techniques.

PAGE 8

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS

The Company reports certain contracts and instruments at fair value in accordance with generally accepted accounting principles. Market pricing and indicative price information from external sources are used to measure fair value when available. In the absence of this information, the Company estimates fair value based on near-term and historical price information and statistical methods. For individual contracts, the use of differing assumptions could have a material effect on the contract's estimated fair value. See Note 2 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002 for a discussion of the Company's estimation techniques.(Continued)

The results of operations for the interim periods are not necessarily indicative of the results expected for the full year. Information for quarterly periods is affected by seasonal variations in sales, rate changes, timing of purchased gas expense recovery and other factors.

Certain amounts in the ~~2002~~2003 Consolidated Financial Statements have been reclassified to conform to the ~~2003~~2004 presentation. Note 3. Recently Adopted Accounting Standards

~~Accounting~~2004 FIN ~~for Asset Retirement Obligations~~46R

~~Effective~~The ~~January 1, 2003, the~~ Company adopted ~~Statements of~~ Financial Accounting Standards Board (~~SFAS~~FASB) Interpretation No. ~~143~~46 (revised December 2003), ~~Accounting~~Consolidation ~~for~~of ~~Asset~~Variable ~~Retirement~~Interest ~~Obligations~~Entities, ~~which~~(FIN ~~provides~~46R) ~~accounting~~for ~~requirements~~its ~~for~~interests ~~the~~in ~~recognition~~variable ~~and~~interest ~~measurement~~entities of(VIEs) ~~liabilities~~that ~~associated~~are ~~with~~not ~~the~~considered ~~retirement~~special ofpurpose ~~tangible~~entities ~~long-lived~~on ~~assets~~March 31, 2004. ~~The~~FIN ~~Company~~46R ~~has~~addresses ~~identified~~the ~~certain~~identification ~~asset~~and ~~retirement~~consolidation ~~obligations~~of ~~that~~VIEs, which are ~~subject~~entities tothat ~~the~~are ~~standard.~~not ~~These~~controllable ~~obligations~~through ~~are~~voting ~~primarily~~interests ~~associated~~or ~~with~~in which the ~~abandonment~~VIEs' ofequity ~~certain~~investors ~~natural~~do ~~gas~~not ~~pipelines~~bear ~~and~~ the ~~dismantlement~~residual economic risks and ~~restoration~~rewards. ~~activities~~There ~~for~~was ~~its~~no ~~gas~~impact ~~and~~on ~~oil~~the ~~wells~~Company's ~~and~~results ~~platforms.~~of operations or financial position related to this adoption.

InAs ~~addition,~~described ~~the~~more ~~Company~~fully ~~has~~in ~~identified~~Note ~~asset~~3 ~~retirement obligations related~~ to ~~its~~the ~~natural~~Consolidated ~~gas~~Financial ~~gathering,~~Statements ~~storage, transmission and distribution systems, including approximately 2,300 gas storage wells~~ in the Company's ~~underground~~Annual ~~natural~~Report ~~gas~~on ~~storage~~Form ~~network.~~10-K ~~These~~for ~~obligations result from certain safety requirements to be performed at~~ the ~~time~~year ~~any~~ended ~~pipeline~~December or31, ~~storage well is abandoned. However~~2003, the Company ~~expects~~adopted toFIN ~~operate~~46R for its ~~natural~~interests ~~gas gathering, storage, transmission and distribution systems~~ in ~~perpetuity.~~special ~~Thus,~~purpose ~~such~~entities ~~asset~~on ~~retirement~~December obligations 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. Generally31, ~~this will occur based on expected retirement or abandonment of individual pipelines or storage wells based on the Company's operational planning~~2003.

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, other than the cumulative effect of a change in accounting principle, for the three and nine months ended September 30, 2003 ~~was not material.~~

~~Accounting~~SFAS ~~for~~No. ~~Certain Financial Instruments with Characteristics of Both Liabilities and Equity~~143

Effective ~~July~~January 1, 2003, the Company adopted Statement of Financial Accounting Standards (SFAS) No. ~~150~~143, Accounting for ~~Certain~~Asset ~~Financial~~Retirement ~~Instruments~~Obligations, ~~with~~which ~~Characteristics~~provides ofaccounting ~~Both~~requirements ~~Liabilities~~for ~~and~~the ~~Equity.~~recognition ~~The~~and ~~standard~~measurement ~~requires an issuer to classify certain financial instruments with characteristics~~ of ~~both~~ liabilities ~~and~~associated ~~equity~~with ~~as a liability if~~ the ~~issuer~~retirement isof ~~obligated~~tangible tolong-lived ~~redeem such instruments~~assets. AsUpon ~~a result~~adoption, ~~beginning July 1, 2003,~~ the Company ~~presents~~recognized ~~the mandatorily redeemable preferred securities issued by~~ a ~~subsidiary~~$5 ~~trust~~million ~~as long~~after-~~term~~tax ~~debt~~loss ~~and related distributions~~ as ~~interest~~the ~~expense.~~cumulative ~~These~~effect ~~securities~~of ~~are~~this ~~described~~change in ~~Note~~accounting ~~17 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002~~principle.

Note 4. Classification of Oil and Gas Drilling Rights

Companies with oil and gas exploration and production operations have become aware that a question has arisen about whether oil and gas drilling rights should be classified as intangible assets rather than tangible assets on the balance sheet. In July 2004, the FASB issued a proposed staff position to clarify that an exception outlined in SFAS No. 142, Goodwill and Other Intangible Assets, includes the balance sheet classification of drilling and mineral rights of oil and gas producing entities. Under FASB's proposal, the Company would continue to present its oil and gas drilling rights ($3.7 billion at June 30, 2004) as tangible assets.

Note 5. Recently Issued Accounting Standards

EITF 03-1

In March 2004, the FASB ratified the consensus reached by the Emerging Issues Task Force (EITF) on Issue No. 03-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments. EITF 03-1 provides guidance for evaluating whether certain investments in debt and equity securities are other-than-temporarily impaired and is effective for fiscal periods beginning after June 30, 2004. The Company does not expect a material impact on its Consolidated Financial Statements from the initial application of this new guidance.

PAGE 9

CONSOLIDATED NATURAL GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS- (Continued)

~~Amendment~~Note ~~of SFAS No~~6. Operating ~~133~~Revenue

During the second quarter of 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 reflects decisions made by the FASB and its Derivatives Implementation Group in connection with issues raised about the application of SFAS No. 133. Generally, changes resulting from SFAS No. 149 apply to contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. Although industry efforts to interpret SFAS No. 149 are ongoing, the Company believes that SFAS 149 will not have a material impact on its results of operations and financial position based on an assessment of currently available information.

Note 4. Recently Issued Accounting Standards and Other Accounting Matters

Consolidation of Variable Interest Entities

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, (FIN 46) which addresses the consolidation of "variable interest entities" (VIEs). VIEs are entities that are not controllable through voting interests or in which the equity investors do not bear the residual economic risks and rewards. In October 2003, the FASB decided to permit more time for the implementation of FIN 46 and now requires adoption as of December 31, 2003.

Lease with A Special Purpose Entity

The Company entered into an agreement with another Dominion subsidiary (lessor) in order to finance and lease a power generation facility. Under existing accounting guidance, neither the project assets nor the related obligations are currently reported on the Company's Consolidated Balance Sheets. Under FIN 46, the lessor is considered a VIE and the Company has been determined to be the primary beneficiary and will therefore consolidate the VIE in the preparation of its Consolidated Balance Sheets.

The Company estimates that consolidating this VIE, effective December 31, 2003, will result in an additional $224 million in net property, plant and equipment and $234 million of related debt. The cumulative effect of adopting FIN 46 is estimated to result in an after-tax charge of $7 million, representing depreciation expense associated with the consolidated assets.

At September 30, 2003, the Company's maximum exposure to loss resulting from its interests in the VIE was $192 million based upon total project costs through September 30, 2003. The exposure assumes that the property, plant and equipment will have no value at the end of the lease terms, which the Company believes is highly unlikely.

Trust Preferred Securities

The Company established Dominion 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 notes issued by the Company to be held by the trust. Under existing accounting guidance, the Company consolidates the trust in the preparation of its Consolidated Financial Statements. Under FIN 46, the Company will cease consolidating the trust beginning on December 31, 2003. Upon adoption, the Company's Consolidated Balance Sheets will report the junior subordinated instruments held by the trust as long-term debt, rather than trust preferred securities.

PAGE 10

CONSOLIDATED NATURAL GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

Balance Sheet Classification-Mineral Rights

Companies with gas and oil exploration and production operations have become aware that a question has arisen about whether contractual mineral rights should be classified as intangible assets rather than tangible assets on the balance sheet as a result of SFAS Nos. 141, Business Combinations, and 142, Goodwill and Other Intangible Assets. If, as a result of the resolution of this issue, reclassification of the costs associated with mineral rights is required, the Company's net intangible assets would increase and its net property, plant and equipment would decrease. As of September 30, 2003, the amount subject to reclassification was approximately $3.5 billion. While resolution of this issue may affect the balance sheet classification of these assets, there would be no impact on the Company's results of operations or cash flows.

Balance Sheet Classification-Provision for Future Cost of Removal by Regulated Operations

The Company adopted SFAS No. 143 on January 1, 2003. SFAS No. 143 provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets.

In accordance with applicable regulatory uniform system of accounts and as permitted by SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, the Company's gas utility operations recognize a provision for the cost of future asset removal activities subject to cost-of-service rate regulation, even if no legal obligation to perform such activities exists. The periodic provision is recorded as a component of depreciation expense on the Consolidated Statement of Income, resulting in a credit being recorded in accumulated depreciation, depletion and amortization on the Consolidated Balance Sheet. At September 30, 2003 and December 31, 2002, the Company's accumulated depreciation, depletion and amortization included $206 million and $221 million, respectively, representing regulatory liabilities for the estimated amounts collected from customers for the future cost of such asset removal activities.

A question has recently arisen about whether these regulatory liabilities should continue to be classified in accumulated depreciation, depletion and amortization or be reported as liabilities on the balance sheet. If, as a result of the resolution of this issue, reclassification of this accumulated provision for future removal costs is required, the Company's accumulated depreciation would decrease and its regulatory liabilities would increase. While resolution of this issue may affect the balance sheet classification of these items, there would be no impact on the Company's results of operations or cash flows.

Note 5. Operating Revenue

The Company's operating revenue consists of the following:

	Three Months Ended September 30,		Nine Months Ended September 30,
	Three Months Ended June 30,		Six Months Ended June 30,
	2003	2002	2003	2002
	2004	2003	2004	2003
	(Millions)
	(millions)
Regulated gas sales	$ 120	$ 82	$ 851	$ 542
Operating Revenue
Nonregulated electric sales	72	48	170	78
Regulated gas sales	$183	$180	$843	$731
Nonregulated gas sales	310	166	1,103	600
Nonregulated electric sales	100	45	188	98
Gas transportation and storage	145	131	559	514
Nonregulated gas sales
Gas and oil production	295	249	890	718
External customers	148	171	511	533
Other	80	74	260	218
Affiliated customers	271	161	564	260
Total operating revenue	$1,022	$750	$3,833	$2,670
Gas transportation and storage	165	147	437	414
Gas and oil production	317	298	613	595
Other	117	85	223	180
Total operating revenue	$1,301	$1,087	$3,379	$2,811

~~PAGE~~Note 117. Comprehensive Income

CONSOLIDATED NATURAL GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

Note 6. Comprehensive Income

The following table presents total comprehensive income:

	Three Months Ended September 30,		Nine Months Ended September 30,
	Three Months Ended June 30,		Six Months Ended June 30,
	2003	2002	2003	2002
	2004	2003	2004	2003
	(Millions)
	(millions)
Net income	$~~115~~182	$~~113~~103	$~~465~~493	$~~418~~350
Other comprehensive income (loss)(1)	127	27	(173)	(278)
Other comprehensive income (loss):
Total comprehensive income	$242	$140	$292	$140
Net other comprehensive loss associated with effective portion of the changes in fair value of derivatives designated as cash flows hedges, net of taxes and amounts reclassified to earnings	(76)	(172)	(250)	(318)
Other(1)	(44)	10	(32)	18
Other comprehensive loss	(120)	(162)	(282)	(300)
Total comprehensive income (loss)	$ 62	$ (59)	$211	$ 50

________________

(1) . Represents primarily the impact of foreign currency translation adjustments.

~~Note~~PAGE ~~7. Impairment of CNG International Investments~~10

~~During~~CONSOLIDATED ~~the~~NATURAL ~~second~~GAS ~~quarter~~COMPANY NOTES ofTO ~~2003,~~CONSOLIDATED ~~the~~FINANCIAL ~~Company recognized an impairment loss of $40 million~~ STATEMENTS (~~$25 million after-tax~~Continued) related to certain CNG International Corporation (CNG International) investments classified as assets held for sale on its Consolidated Balance Sheets. The assets included a small generation facility located in Kauai, Hawaii and an equity investment in a pipeline business located in Australia. The impairment loss represented an adjustment to the assets' carrying amounts to reflect the Company's current evaluation of fair value, less estimated costs to sell.

Note 8. ~~Derivative~~ ~~Instruments~~Volumetric ~~and~~Production ~~Hedge~~Payment ~~Accounting~~(VPP) Transaction

~~Selected~~In ~~information~~May ~~about~~2004, the Company received $413 million in cash for the sale of a fixed-term overriding royalty interest in certain of its proved natural gas reserves for the period May 2004 through April 2008. The sale reduced the Company's ~~hedge~~natural ~~accounting~~gas ~~activities~~reserves ~~follows:~~by approximately 83 billion cubic feet (bcf). While the Company is obligated 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 for approximately 66 bcf for the period August 2003 through August 2007.

Note 9. CNG International (CNGI) Investments Held for Sale

	Three Months Ended September 30,		Nine Months Ended September 30,
	2003	2002	2003	2002
	(Millions)
Portion of pre-tax gains (losses) on hedging instruments determined to be ineffective and included in net income:
Fair value hedges	$ (2)	$(2)	$ (1)	$ 1
Cash flow hedges	-	(1)	-	(9)
Net ineffectiveness	$ (2)	$(3)	$ (1)	$ (8)
For options used as hedging instruments, change in options' time value excluded from measurement of effectiveness and included in net income:
Fair value hedges	$ -	$(1)	$ (1)	$ (1)
Cash flow hedges	(3)	-	3	-
Total change in options' time value	$ (3)	$(1)	$ 2	$ (1)
Other comprehensive income (loss), net of taxes-cash flow hedges	$149	$28	$(169)	$(277)

In the second quarter of 2004, the Company received cash proceeds of $48 million and recognized a gain in other income of $8 million from the sale of a portion of the Australian pipeline business in which CNGI has held an investment. In the first quarter of 2004, the Company 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.

Note 10. Hedge Accounting Activities

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

	Three Months Ended June 30,		Six Months Ended June 30,
	(millions)
	2004	2003	2004	2003
Portion of gains (losses) on hedging instruments determined to be ineffective and included in net income:
Fair value hedges	$ (1)	$(1)	-	$ 1
Cash flow hedges	4	(4)	$ 1	-
Net ineffectiveness	$ 3	$(5)	$ 1	$ 1

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	$ 38	2	$ 74	6
Total change in options' time value	$ 38	$ 1	$ 74	$ 5

PAGE 11

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

The following table presents selected information related to cash flow hedges included in accumulated other comprehensive loss in the Consolidated Balance Sheet at June 30, 2004:

	Accumulated Other Comprehensive Loss, After-Tax	Portion Expected to be Reclassified to Earnings During the Next 12 Months, After-Tax	Maximum Term
	(millions)
Commodities:
Gas	$(614)	$(315)	44 months
Oil	(205)	(94)	42 months
Interest Rate	(1)	-	45 months
Total	$(820)	$(409)

The actual amounts that will be reclassified to earnings during the next 12 months 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 accumulated other comprehensive loss to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies.

Note 11. Ceiling Test

The Company follows the full cost method of accounting for gas and oil exploration and production activities prescribed by the SEC. Under the full cost method, 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 hedge-adjusted prices. Approximately 14% 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 June 30, 2004.

PAGE 12

CONSOLIDATED NATURAL GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS- (Continued)

Note 12. Significant Financing Transactions
Accumulated Other Comprehensive Loss After-Tax Portion Expected to be Reclassified to Earnings During the Next 12 Months Maximum Term
(Millions)
Commodities $(449) $(172) 53 months
Interest Rate (17) (1) 123 months
Total $(466) $(173)

Credit Facilities

~~The~~In ~~actual~~June ~~amounts~~2004, ~~that~~the ~~will~~Company beentered ~~reclassified~~into toa ~~earnings~~$300 ~~during~~million ~~the~~letter ~~next~~of 12credit ~~months~~agreement ~~will~~that ~~vary~~terminates ~~from~~in ~~the~~August ~~expected~~2004 ~~amounts~~and ~~presented~~a ~~above~~$100 asmillion aletter ~~result~~ of ~~changes~~credit inagreement ~~market~~that ~~prices~~terminates ~~and~~in ~~interest~~June ~~rates~~2007. ~~The~~These ~~effect~~agreements support letter of ~~amounts~~credit ~~being~~issuances, ~~reclassified~~providing ~~from~~collateral ~~Accumulated~~required ~~Other~~on ~~Comprehensive~~derivative ~~Income~~financial tocontracts ~~earnings~~used ~~will~~by ~~generally~~the beCompany ~~offset~~in byits ~~the~~risk ~~recognition~~management ofstrategies ~~the~~for ~~hedged~~gas ~~transactions~~and (eoil production.~~g.,~~ ~~anticipated~~At ~~sales)~~June in30, ~~earnings~~2004, ~~thereby~~outstanding ~~achieving~~letters ~~the realization~~ of ~~prices~~credit ~~contemplated~~under bythese ~~the~~agreements ~~underlying~~totaled ~~risk~~$300 ~~management strategies~~million.

~~Note~~In 9August 2003, the Company entered into a $1. ~~Ceiling~~0 ~~Test~~billion 364-day revolving credit facility that terminates in August 2004. This credit facility is being used to support the issuance of commercial paper and letters of credit to provide collateral required on derivative financial contracts used by the Company in its risk management strategies for gas and oil production. At June 30, 2004, outstanding letters of credit under this facility totaled $700 million. The Company expects to renew the $1.0 billion 364-day revolving credit facility prior to its maturity in August 2004.

Joint Credit Facilities and Short-Term Debt

~~The~~Dominion, ~~Company~~Virginia ~~follows~~Power, ~~the~~a ~~full~~wholly-owned ~~cost~~subsidiary ~~method~~ of ~~accounting~~Dominion, ~~for gas~~ and ~~oil~~the ~~exploration~~Company ~~and~~have ~~production~~two ~~activities,~~three-year asrevolving ~~prescribed~~joint bycredit ~~the~~facilities ~~SEC.~~that ~~Under~~allow ~~this~~aggregate ~~method,~~borrowings ~~capitalized~~of ~~costs~~up ~~are subject~~ to a$2.25 ~~quarterly "ceiling test~~billion." ~~Under~~The ~~the~~facilities ~~ceiling~~include ~~test,~~a ~~amounts~~$1.5 ~~capitalized~~billion ~~are~~credit ~~limited~~facility tothat ~~the~~was ~~present~~entered ~~value~~into ofin ~~estimated~~May ~~future~~2004 ~~net~~and ~~revenue~~terminates toin beMay ~~derived~~2007 ~~from~~and ~~the~~a ~~anticipated~~$750 ~~production~~million ofcredit ~~proved~~facility ~~gas~~that ~~and~~was ~~oil~~entered ~~reserves,~~into ~~assuming~~in ~~period-end~~May ~~market~~2002 ~~prices.~~and ~~Approximately~~terminates 17in ~~percent~~May of2005. ~~the~~These ~~Company's~~credit ~~anticipated~~facilities ~~production~~are ~~that~~being isused ~~hedged~~for byworking ~~qualifying~~capital, ~~cash~~as ~~flow~~support ~~hedges~~ for ~~which~~the ~~hedge-adjusted~~combined ~~prices~~commercial ~~were~~paper ~~used~~programs toof ~~calculate~~Dominion, ~~estimated~~Virginia ~~future~~Power ~~net~~and ~~revenue.~~the ~~Whether~~Company ~~period-end~~and ~~market~~the ~~prices~~issuance orof ~~hedge-adjusted~~letters ~~prices~~of ~~were~~credit ~~used~~of ~~for~~up ~~the~~to ~~portion~~$500 ofmillion ~~production~~under ~~that~~the is$1.5 ~~hedged,~~billion ~~there~~credit ~~was~~facility noand ~~ceiling~~$200 ~~test~~million ~~impairment~~under asthe of$750 ~~September~~million ~~30,~~credit ~~2003~~facility.

~~Note~~ At 10June 30, 2004, total outstanding commercial paper supported by the credit facilities was $610 million. ~~Significant~~ ~~Financing~~At ~~Transactions~~June 30, 2004, the Company did not have any commercial paper borrowings. At June 30, 2004, total outstanding letters of credit supported by the credit facilities were $478 million, of which $275 million was issued on behalf of the Company. At June 30, 2004, capacity available under the two credit facilities was $1.16 billion.

Joint Credit Facilities
PAGE 13
CONSOLIDATED NATURAL GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Credit Facility
In August 2003, the Company entered into a $1 billion credit facility. This 364-day revolving credit facility, which terminates in August 2004, will be 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 September 30, 2003, outstanding letters of credit under these facilities totaled $586 million.

Long-Term Debt

In ~~August~~June ~~2003~~2004, the Company repaid $~~150~~88 million of 5its 9.7525% ~~percent~~ senior notes.

Shelf Registration

At ~~September~~June 30, ~~2003~~2004, the Company had $1.53 billion of available capacity under a shelf registration with the SEC that would permit the Company to issue debt and trust preferred securities to meet future capital requirements.

~~Note~~ The 11Company's current financing authorization under the 1935 Act expires at the end of 2004. ~~Asset~~ ~~Retirement~~The ~~Obligations~~Company intends to file an application with the SEC in August 2004 to renew its 1935 Act financing authorization.

~~The~~PAGE ~~following table describes the changes to the Company's asset retirement obligations during the nine months ended September 30, 2003:~~13

Amount
(Millions)
Asset retirement obligations at January 1, 2003 $ -
Asset retirement obligations recognized in transition 198
Asset retirement obligations incurred during the period 2
Asset retirement obligations settled during the period (6)
Accretion expense 7
Revisions in estimated cash flows (1)
Asset retirement obligations at September 30, 2003 $200
CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

~~Had~~ Note ~~the provisions of SFAS No~~13. Commitments ~~143 been applied for the following periods in 2003~~ and ~~2002, the Company's net income would have been as follows:~~Contingencies

	Three Months Ended September 30,		Nine Months Ended September 30,
	2003	2002	2003	2002
	(Millions)
Net income, as reported	$115	$113	$465	$418
Pro forma net income	$115	$111	$470	$413

Other than the matters discussed below, there have been no significant developments regarding the commitments and contingencies disclosed in Note 20 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2003, or Note 11 to the Consolidated Financial Statements in the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, nor have any significant new matters arisen during the quarter ended June 30, 2004.

Guarantees, Letters of Credit and Surety Bonds

~~Note~~As 12of June 30, 2004, the Company had issued $1. ~~Commitments~~4 billion of guarantees, including: $1.0 billion to support commodity transactions of subsidiaries, $200 million for subsidiary debt and ~~Contingencies~~$184 million for guarantees supporting other agreements of subsidiaries. The Company had also purchased $49 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $1.3 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 guarantee. No such liabilities have been recognized as of June 30, 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.

~~Other than the matters discussed below, there have been no significant developments with regard to commitments and contingencies as disclosed in~~ Note 2114. toCredit ~~the~~Risk Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002, nor have any significant new matters arisen during the nine months ended September 30, 2003.

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, in its hedging activities. 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 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 June 30, 2004, gross credit exposure related to these transactions totaled $439 million, reflecting the unrealized gains for contracts carried at fair value plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral. After the application of collateral, the Company's credit exposure is reduced to $438 million. Of this amount, investment grade counterparties represent 51% and no single counterparty exceeded 5%. The credit exposure amounts exclude amounts receivable from affiliated companies. As of June 30, 2004 and December 31, 2003, the Company had margin deposit assets (reported in other current assets) of $46 million and $59 million, respectively. The Company had $1 million of margin deposit liabilities (reported in other current liabilities) as of June 30, 2004. The Company had no margin deposit liabilities as of December 31, 2003.

PAGE 14

CONSOLIDATED NATURAL GAS COMPANY ~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)~~

~~Fuel~~ NOTES ~~Purchase~~TO ~~Commitments~~CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 15. Related Party Transactions

The Company ~~enters~~engages ~~into~~in ~~long-term~~related ~~purchase~~party ~~commitments~~transactions ~~for~~primarily ~~natural~~with ~~gas.~~other AsDominion ofsubsidiaries. ~~September~~The ~~30,~~Company's ~~2003,~~accounts ~~estimated~~receivable ~~payments under these commitments are as follows: 2004-$160 million; 2005-$100 million; 2006-$20 million; 2007-$20 million;~~ and ~~years~~payable ~~beyond~~balances ~~2007-$215~~with ~~million.~~affiliates ~~These~~are ~~purchase~~settled ~~commitments~~based ~~include~~on ~~those~~contractual ~~required~~terms ~~for~~or ~~regulated~~on ~~operations.~~a ~~The~~monthly ~~Company~~basis, ~~generally~~depending ~~recovers~~on the ~~costs~~nature of ~~those~~the ~~purchases~~underlying ~~through regulated rates~~transactions. The ~~natural~~significant ~~gas~~related ~~purchase~~party ~~commitments~~transactions ~~of the Company's field services operations~~ are ~~also~~disclosed ~~included, net of related sales commitments~~below.

~~Lease~~ Transactions ~~Commitments~~with Other Dominion Subsidiaries

The Company ~~entered~~transacts ~~into agreements~~ with aother Dominion ~~subsidiary~~subsidiaries ~~(lessor)~~for incertain ~~order~~quantities toof ~~finance~~natural gas and ~~lease~~other acommodities ~~power~~at ~~generation~~market ~~facility.~~prices Onin ~~December~~the ~~31,~~ordinary ~~2003,~~course ~~the~~of business. The Company ~~will~~also ~~consolidate~~enters ~~the~~into ~~VIE~~certain ~~that~~financial ~~includes~~derivative ~~the~~commodity ~~generation~~contracts ~~facility~~with ~~assets~~Dominion ~~and~~subsidiaries. ~~related~~These ~~debt~~contracts, aswhich are principally comprised of commodity swaps and options, are used by the Company ~~has~~to ~~been~~manage ~~determined~~commodity toprice berisks associated with the ~~primary~~purchases ~~beneficiary~~and ~~under~~sales ~~FIN~~of 46natural gas. AsThe aCompany ~~result,~~designates ~~previously~~the ~~disclosed~~majority ~~future~~of ~~minimum~~these ~~lease~~contracts ~~payments~~as ~~will~~cash beflow ~~reduced~~hedges byfor ~~the~~accounting ~~following~~purposes. ~~amounts:~~The ~~2004-$13~~affiliated ~~million;~~commodity ~~2005-$13~~transactions ~~million;~~below ~~2006-~~include total net realized gains on affiliate commodity derivative transactions of $137 million; and ~~2007-~~$1320 million. ~~Similar~~in ~~amounts~~the ~~for~~second ~~these~~quarter ~~periods~~of ~~will~~2004 beand ~~recognized~~2003, asrespectively, ~~interest~~and ~~expense~~$10 ~~associated~~million ~~with~~and $25 million in the ~~newly~~first ~~consolidated~~six ~~debt~~months ~~obligation~~of 2004 and 2003, respectively.

Guarantees, Letters of Credit and Surety Bonds

	Three Months Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
	(millions)
Purchases of natural gas from affiliates	$129	$170	$279	$295
Purchases of electric fuel and energy from affiliates	53	17	91	27
Sales of natural gas to affiliates	271	161	564	260
Sales of gas transportation and storage services to affiliates	5	6	12	16
Sales of electricity to affiliates	14	4	22	8

~~Equity~~ The ~~Contribution~~Company's ~~Commitment~~Consolidated Balance Sheets include derivative assets of $26 million and $50 million with Dominion subsidiaries at June 30, 2004 and December 31, 2003, respectively, and derivative liabilities of $49 million and $48 million with Dominion subsidiaries at June 30, 2004 and December 31, 2003, 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 balance of accumulated other comprehensive loss in the Consolidated Balance Sheets.

InDominion ~~October~~Resources ~~2003~~Services, ~~the~~Inc., ~~Company~~a ~~made~~Dominion ansubsidiary, ~~equity~~provides ~~contribution~~accounting, oflegal ~~$100~~and ~~million~~certain inadministrative ~~connection~~and ~~with~~technical ~~CNG~~services ~~International's~~to ~~equity~~the ~~investment~~Company. inThe ~~Australian~~Company ~~natural~~recognized ~~gas~~expense ~~pipelines~~of ~~under~~$39 anmillion ~~agreement~~in ~~associated~~both ~~with~~the asecond ~~debt~~quarter ~~financing.~~of ~~The~~2004 ~~Company~~and ~~was~~2003, ~~contractually~~and ~~obligated~~$83 tomillion ~~make~~and ~~such~~$86 ~~equity~~million ~~contribution~~in tothe ~~ensure~~first ~~repayment~~six months of ~~the~~2004 ~~debt~~and ~~that~~2003, ~~matured~~respectively, in ~~October~~operations ~~2003~~and maintenance expense related to these services.

Transactions with Dominion

~~Note~~As 13of June 30, 2004 and December 31, 2003, the Company and its subsidiaries have borrowed funds from Dominion under the Dominion money pool ($534 million and $901 million, respectively) and a short-term demand note ($111 million and $126 million, respectively). ~~Concentration~~ During the second quarter of ~~Credit~~2004 ~~Risk~~and 2003, the Company incurred $3 million in each period in interest charges related to these borrowings. During the first six months of 2004 and 2003, the Company incurred $5 million and $6 million, respectively, in interest charges related to these borrowings.

PAGE 15

CONSOLIDATED NATURAL GAS COMPANY ~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)~~

At September 30, 2003 Credit Exposure (Millions)
Investment grade(1) $129
Non-investment grade(2) 11
No external ratings:
Internally rated-investment grade(3) 39
Internally rated-non-investment grade(4) 90
Total $269

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 16. Employee Benefit Plans

~~________________~~ The following table illustrates the components of the provision for net periodic benefit cost for the Company's defined benefit pension and other postretirement benefit plans for employees represented by collective bargaining units:

	Pension Benefits		Other Postretirement Benefits
	2004	2003	2004	2003
Three Months Ended June 30,	(millions)
Service cost	$ 2	$ 2	$ 5	$ 3
Interest cost	7	8	7	5
Expected return on plan assets	(25)	(24)	(4)	(2)
Amortization of transition obligation	-	(1)	2	1
Amortization of net (gain) loss	-	(2)	2	2
Net periodic benefit cost (credit)	$(16)	$(17)	$12	$9

Company's net periodic benefit cost (credit)⁽¹⁾	$(28)	$(33)	$17	$14

Six Months Ended June 30,
Service cost	$ 5	$ 4	$ 9	$ 6
Interest cost	15	15	13	11
Expected return on plan assets	(50)	(48)	(7)	(4)
Amortization of transition obligation	(1)	(2)	3	2
Amortization of net (gain) loss	-	(4)	5	4
Net periodic benefit cost (credit)	$(31)	$(35 )	$23	$19

Company's net periodic benefit cost (credit)⁽¹⁾	$(56)	$(66)	$32	$28

__________
⁽¹⁾Amounts represent all benefit plans in which the Company participates, including benefit plans covering multiple Dominion subsidiaries.

~~(2)~~ Employer Contributions

~~(3)~~ The Company made no contributions to its defined benefit pension plans or other postretirement benefit plans during the first six months of 2004. The Company expects to contribute at least $51 million to its other postretirement benefit plans during the remainder of 2004. 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 additional contributions to be made in 2004 will be determined at that time.

(4)

Note 14. Related Party Transactions

The Company transacts with other Dominion affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. The affiliated commodity transactions are presented below:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2003	2002	2003	2002
	(Millions)
Purchases of natural gas from affiliates	$166	$54	$489	$161
Sales of natural gas, gas transportation and storage services to affiliates
	185	41	462	105
Purchases of electricity from affiliates	20	9	45	16
Sales of electricity to affiliates	11	8	19	14

The Company enters into certain commodity derivative contracts with Dominion affiliates. These contracts, which are principally comprised of commodity swaps, are used by the Company to manage commodity price risks associated with purchases and sales of natural gas. The Company designates the majority of these contracts as hedges for accounting purposes. At September 30, 2003 and December 31, 2002, the Company's Consolidated Balance Sheets included derivative assets with Dominion affiliates of $51 million and $55 million, respectively, and derivative liabilities with Dominion affiliates of $54 million and $48 million, respectively. Unrealized gains or losses, representing the effective portion of the changes in fair value of these affiliate derivative contracts, are included in the balance of Accumulated Other Comprehensive Income in the Company's Consolidated Balance Sheets. The Company's income from operations includes the recognition of the following derivative gains and losses on affiliated transactions:

PAGE 16

CONSOLIDATED NATURAL GAS COMPANY ~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)~~

Three Months Ended September 30, Nine Months Ended September 30,
2003 2002 2003 2002
(Millions)
Net realized gains (losses) on commodity derivative contracts $(2) $(7) $22 $(38)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

~~See~~ Note ~~8 for a discussion of the Company's hedging activities~~17. Operating Segments

~~Dominion~~The ~~Resources~~Company ~~Services,~~is ~~Inc.~~organized ~~(Dominion~~primarily ~~Services)~~on ~~provides certain administrative and technical services to~~ the ~~Company.~~basis ~~The cost~~ of ~~services~~products ~~provided by Dominion Services to the Company for the three months ended September 30, 2003~~ and ~~2002~~services ~~was~~sold ~~approximately~~in ~~$38 million and $42 million, respectively, and was approximately $121 million and $123 million for~~ the ~~nine~~United ~~months ended September 30, 2003 and 2002, respectively~~States. The ~~cost of services provided by the~~ Company tomanages ~~Dominion~~its ~~Services~~operations ~~and~~based ~~other~~on ~~Dominion affiliates for the~~ three ~~months~~primary ~~ended~~operating September 30, 2003 and 2002 was approximately $3 million and $2 million, respectively, and was approximately $8 million and $5 million for the nine months ended September 30, 2003 and 2002, respectively.segments:

~~Effective~~Energy ~~March~~includes ~~1, 2003, a consolidated Dominion money pool was formed and~~ the existing CNG money pool was terminated pursuant to a SEC order. Outstanding balances under the CNG money pool and certain borrowings from Dominion pursuant to a short-term demand note were converted to Dominion money pool borrowings on March 1, 2003. In September 2003, Dominion made a $600 million equity contribution to the Company ~~that was accomplished by reducing the money pool borrowings of the Company~~'s ~~subsidiaries.~~gas Attransmission ~~September~~pipeline ~~30,~~and ~~2003,~~storage ~~net outstanding borrowings under the Dominion money pool totaled $541 million. At September 30~~system, ~~2003~~certain ~~and~~gas ~~December~~production 31operations, ~~2002,~~a ~~net~~liquefied ~~outstanding~~natural ~~borrowings~~gas ~~under~~import ~~the demand note totaled $132 million~~ and ~~$563~~storage ~~million,~~facility ~~respectively. During the three~~ and ~~nine~~producer ~~months~~services ~~ended~~operations ~~September~~that ~~30,~~include ~~2003,~~aggregation ~~the~~of ~~Company~~gas ~~incurred~~supply ~~approximately $4 million~~ and ~~$10 million, respectively, of interest charges~~ related towholesale ~~these borrowings~~activities.

~~The Company's accounts receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions.~~Delivery
includes the Company's regulated gas distribution systems and customer service operations and the Company's nonregulated retail energy marketing activities.

~~The~~ Exploration ~~Company~~& ~~entered~~Production ~~into~~includes anthe ~~agreement~~Company's ~~with~~onshore aand ~~Dominion~~offshore ~~subsidiary~~gas inand ~~order~~oil ~~to develop~~exploration, ~~construct,~~development ~~finance~~ and ~~lease~~production ~~a power generation facility in Armstrong, Pennsylvania~~operations. ~~The~~These ~~Company~~operations ~~will~~are ~~adopt~~located ~~FIN~~in 46several onmajor ~~December~~producing ~~31,~~basins ~~2003 by consolidating its interests~~ in ~~this~~the ~~VIE~~lower ~~that~~48 ~~includes~~states, including the ~~power~~outer ~~generation~~continental ~~facility~~shelf ~~assets~~ and ~~related~~deepwater ~~debt~~areas onof the ~~Company's~~Gulf ~~Consolidated~~of ~~Balance Sheets~~Mexico.

~~Note~~Corporate 15and Other includes the Company's corporate and other functions, including the activities of CNGI and other minor subsidiaries. ~~Volumetric~~ ~~Production~~The ~~Payment~~contribution ~~Transaction~~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 instead reported in the Corporate and Other segment.

In August 2003, the Company received $266 million in cash for the sale of a fixed-term overriding royalty interest in certain of its natural gas reserves for the period August 2003 through August 2007. The sale reduced the Company's natural gas reserves by approximately 66 billion cubic feet (bcf). While the Company is obligated 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 66 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 volumetric production payment transaction were recorded as deferred revenue. The Company will recognize revenue from the transaction as natural gas is produced and delivered to the purchaser.

	Energy	Delivery	Exploration & Production	Corporate and Other	Eliminations	Consolidated Total
	(millions)
Three Months ended June 30, 2004
Operating revenue - external customers	$463	$391	$430	$ 17	$ -	$1,301
Operating revenue - intersegment	52	15	34	-	(101)	-
Net income (loss)	38	28	144	(28)	-	182

Three Months ended June 30, 2003
Operating revenue - external customers	$378	$326	$371	$12	$ -	$1,087
Operating revenue - intersegment	50	12	30	-	(92)	-
Net income (loss)	40	11	75	(23)	-	103

Six Months Ended June 30, 2004
Operating revenue - external customers	$1,029	$1,521	$802	$ 27	$ -	$3,379
Operating revenue - intersegment	111	34	68	-	(213)	-
Net income (loss)	121	127	253	(8)	-	493

Six Months Ended June 30, 2003
Operating revenue - external customers	$797	$1,235	$755	$24	$ -	$2,811
Operating revenue - intersegment	119	25	67	-	(211)	-
Net income (loss)	121	103	159	(33)	-	350

PAGE 17

CONSOLIDATED NATURAL GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Note 16. Operating Segments
The Company is organized primarily on the basis of products and services sold in the United States. The Company manages its operations based on three primary business lines:
The Delivery segment manages the Company's retail gas distribution systems and customer service operations.
The Energy segment manages the Company's retail marketing of energy services in nonregulated markets, gas transmission and storage operations, certain gas production and the Company's nonregulated sales of electricity.
The Exploration & Production segment manages the Company's onshore and offshore 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 deep-water areas of the Gulf of Mexico.
In addition, the Company reports its corporate and other functions as a segment. The Corporate and Other segment includes activities of CNG International and other minor subsidiaries, costs of the Company's corporate and other functions as well as certain items attributable to activities of the other segments. Items included in the Corporate and Other segment for the nine months ended September 30, 2003 follow:
Impairment loss related to certain CNG International investments classified as assets held for sale (see Note 7);
Severance costs related to the Company's workforce reductions; and
Cumulative effect of a change in accounting principle related to the adoption of SFAS No. 143 (see Note 3).
Delivery Energy Exploration & Production Corporate and Other Eliminations Consolidated Total
(Millions)
Three Months Ended September 30, 2003
Operating revenue-external customers $ 176 $ 469 $ 372 $ 5 $ - $1,022
Operating revenue-intersegment 1 24 30 - (55) -
Net income (loss) 3 36 77 (1) - 115
Three Months ended September 30, 2002
Operating revenue-external customers $ 132 $ 303 $ 314 $ 1 $ - $ 750
Operating revenue-intersegment - 15 17 - (32) -
Net income (loss) (3) 42 63 11 - 113
Nine Months Ended September 30, 2003
Operating revenue-external customers $1,130 $1,561 $1,127 $ 15 $ - $3,833
Operating revenue-intersegment 3 77 97 - (177) -
Net income (loss) 109 156 236 (36) - 465
Nine Months ended September 30, 2002
Operating revenue-external customers $ 795 $ 954 $ 920 $ 1 $ - $2,670
Operating revenue-intersegment 1 61 43 - (105) -
Net income 91 147 174 6 - 418
PAGE 18
CONSOLIDATED NATURAL GAS COMPANY

ITEM 2. 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 and general financial condition of the Company. MD&A should be read in conjunction with the Consolidated Financial Statements. The "Company" is used throughout MD&A and, depending on the context of its use, may represent any of the following: the legal entity, 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

~~Introduction~~ The MD&A consists of the following information:

Forward-Looking Statements
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 ~~the~~predicted results ~~predicted~~. Factors that ~~could~~may cause actual results to differ are often presented with the forward-looking statements themselves. ~~In addition~~Additionally, other ~~factors~~risks ~~could~~that may cause actual results to differ ~~materially~~ from ~~those~~predicted ~~indicated~~results inare ~~any~~set ~~forward-looking~~forth ~~statement. These factors include weather conditions; governmental regulations; cost of environmental compliance; fluctuations~~ in ~~energy-related~~Risk ~~commodities~~Factors ~~prices~~ and ~~the~~Cautionary ~~effect~~Statements ~~these~~That ~~could~~May ~~have~~Affect onFuture the Company's earnings, liquidity position and the underlying value of its assets; counterparty credit risk; capital market conditions, including equity price risk due to marketable equity securities held as investments in benefit plans; fluctuations in interest rates; changes in rating agency requirements or ratings; changes in accounting standards; the risks of operating businesses in regulated industries that are becoming deregulated; completing the divestiture of investments held by CNG International; collective bargaining agreements and labor negotiations; and political and economic conditions (including inflation and deflation)Results. ~~Some more specific risks are discussed below.~~

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.

Accounting Matters

~~The~~Critical ~~Company's~~Accounting ~~operations~~Policies ~~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~~Estimates ~~the price of energy commodities. In addition, severe weather, including hurricanes, can be destructive, disrupting operations and causing production delays and unusual maintenance or repairs.~~

~~The~~As ~~Company~~of isJune ~~subject~~30, to2004, ~~complex~~there ~~governmental~~have ~~regulation~~been ~~that~~no ~~could~~significant ~~adversely~~changes ~~affect~~with ~~its~~regard ~~operations-The Company's operations are subject~~ to ~~extensive~~critical ~~regulation~~accounting ~~and~~policies ~~require numerous permits, approvals~~ and ~~certificates~~estimates ~~from~~as ~~federal,~~disclosed ~~state~~in ~~and~~MD&A ~~local~~in ~~governmental~~the ~~agencies. The~~ Company's ~~must~~Annual ~~also~~Report ~~comply~~on ~~with~~Form ~~environmental~~10-K ~~legislation and other regulations. Management believes that the necessary approvals have been obtained~~ for the ~~Company's~~year ~~existing~~ended ~~operations~~December ~~and~~31, ~~that~~2003. ~~its~~The ~~business~~policies isdisclosed ~~conducted~~included inthe ~~accordance~~accounting ~~with~~for: ~~applicable~~derivative ~~laws.~~contracts ~~However,~~at ~~new~~fair ~~laws~~value; orgoodwill ~~regulations,~~and orlong-lived ~~the~~asset ~~revision~~impairment ortesting; ~~reinterpretation~~employee ofbenefit ~~existing~~plans; ~~laws~~regulated oroperations; ~~regulations,~~and ~~may~~gas ~~require~~and ~~the~~oil ~~Company to incur additional expenses~~operations.

PAGE 18

CONSOLIDATED NATURAL GAS COMPANY

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS

FIN 46R

The Company adopted FIN 46R for its interests in VIEs that are not considered special purpose entities on March 31, 2004. FIN 46R addresses the identification and consolidation of VIEs, which are entities that are not controllable through voting interests or in which the VIEs' equity investors do not bear the residual economic risks and rewards. There was no impact on the Company's results of operations or financial position related to this adoption.

Results of Operations

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

	Three Months Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
	(millions)
Energy	$ 38	$ 40	$ 121	$ 121
Delivery	28	11	127	103
Exploration & Production	144	75	253	159
Primary operating segments	210	126	501	383

Corporate and Other	(28 )	(23 )	(8 )	(33 )
Consolidated net income	$182	$103	$493	$350

Overview

Three Months Ended June 30, 2004 vs. 2003

Net income for the second quarter of 2004 increased 77% to $182 million, as compared to the second quarter of 2003. The Company's primary operating segments contributed an additional $84 million to net income. This increase largely reflects:

A higher contribution from the delivery operations, primarily reflecting higher margins on gas and electric sales; and

A higher contribution from exploration and production operations due to lower operations and maintenance expenses, which decreased primarily due to favorable changes in the fair value of certain oil options, and lower income taxes as the result of updated estimates for the combined effective state income tax rate. Results were also affected by the recognition of revenue in connection with deliveries under the VPP agreements, partially offset by lower gas production, reflecting the sale of mineral rights under the VPP agreements.

Six Months Ended June 30, 2004 vs. 2003

Net income for the six months ended June 30, 2004 increased 41% to $493 million, as compared to the first six months of 2003. The Company's primary operating segments contributed an additional $118 million to net income. This increase largely reflects:

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

A higher contribution from exploration and production operations due to lower operations and maintenance expenses, which decreased primarily due to favorable changes in the fair value of certain oil options, and lower income taxes as the result of updated estimates for the combined effective state income tax rate. Results were also affected by the recognition of revenue in connection with deliveries under the VPP agreements, partially offset by lower gas production, reflecting the sale of mineral rights under the VPP agreements.

Net income was also favorably impacted in Corporate and Other for the CNGI investments that are classified as held for sale, including an $8 million gain on the sale of a portion of CNGI's investment in an Australian pipeline business in June 2004. The increase also reflects adjustments to the carrying amount of certain CNGI's investments classified as held for sale.

PAGE 19

CONSOLIDATED NATURAL GAS COMPANY

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS
(Continued)

~~Costs~~Analysis of ~~environmental~~Consolidated ~~compliance,~~Operations liabilities and litigation could exceed the Company's estimates-Compliance with federal, state and local environmental laws and regulations may result in increased capital, operating and other costs, including remediation and containment 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 costs and compliance, 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.
Presented below are selected amounts related to the Company's results of operations.

The use of derivative instruments could result in financial losses-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 value of the reported fair value of these contracts. For additional information concerning derivatives, see Management's Discussion and Analysis of Results of Operations-Market Rate Sensitive Instruments and Risk Management and Notes 2 and 11 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

	Three Months Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
	(millions)
Operating Revenue
Regulated gas sales	$ 183	$ 180	$ 843	$ 731
Nonregulated electric sales	100	45	188	98
Nonregulated gas sales	419	332	1,075	793
Gas transportation and storage	165	147	437	414
Gas and oil production	317	298	613	595
Other	117	85	223	180

Operating Expenses
Purchased gas, net	500	405	1,564	1,194
Electric fuel and energy purchases	88	37	168	82
Liquids, pipeline capacity and other purchases	58	43	109	96
Other operations and maintenance	121	192	273	378
Depreciation, depletion and amortization	154	150	308	290
Other taxes	54	48	136	130

Other income (expense)	11	(9)	40	(8)
Interest and related charges	41	40	83	79
Income tax expense	114	60	285	199

Cumulative effect of changes in accounting principle (net of income taxes)	-	-	-	(5)

~~The~~An ~~Company's~~analysis exploration and production business is dependent on factors including commodity prices which cannot be predicted or controlled-The Company's exploration and production business is subject to risks beyond its control. These factors include fluctuations in natural gas and crude oil prices, results of ~~future drilling and well completion activities,~~ the Company's ability to acquire additional land positions in competitive lease areas, as well as inherent operational risks that could disrupt production. In addition, in connection with the use of financial derivatives to hedge future sales of gas and oil production, the Company's liquidity may sometimes be affected by margin requirements. Under these requirements, the Company must deposit funds with counterparties to cover the fair value of covered contracts in excess of agreed-upon credit limits. Some of these factors could have compounding effects that could also affect the Company's financial results. ~~Also, because the Company follows the full cost method~~ of ~~accounting~~operations for ~~gas and oil exploration and production activities prescribed by~~ the ~~SEC,~~three ~~short-term market declines in the prices of natural gas~~ and ~~oil~~six ~~could~~months ~~adversely~~ended ~~affect~~June ~~its financial results. Under the full cost method~~30, ~~all direct costs of property acquisition~~2004, ~~exploration~~as ~~and~~compared ~~development~~to ~~activities are capitalized. The principal limitation is that these capitalized amounts may not exceed~~ the ~~present~~same ~~value~~periods of ~~estimated~~2003 ~~future net revenue based on hedge-adjusted period-end prices from the production of proved gas and oil reserves (the ceiling test)~~follows. ~~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.~~

AnThree ~~inability~~Months toEnded ~~access~~June 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. However30, ~~certain~~2004 ~~disruptions outside of the Company's control may increase its cost of borrowing or restrict its ability to access one or more financial markets~~vs. ~~Such~~2003 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.

Operating Revenue

Nonregulated electric sales revenue
increased 122% to $100 million resulting primarily from customer growth in nonregulated retail energy sales.

PAGE 20

CONSOLIDATED NATURAL GAS COMPANY

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS
(Continued)

~~Changing~~Nonregulated ~~rating~~gas ~~agency~~sales ~~requirements~~revenue ~~could~~increased ~~negatively~~26% affect the Company's growth and business strategy-As of November 3, 2003, the Company's senior unsecured debt was rated BBB+, stable outlook, by Standard & Poor's, and A3, negative outlook, by Moody's. Both agencies have recently implemented more stringent applications of the financial requirements for various ratings levels. In order to ~~maintain~~$419 ~~its~~million ~~current~~primarily 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. reflecting:

~~Potential~~A ~~changes~~$65 inmillion ~~accounting~~increase ~~practices may adversely affect the Company's financial results-The Company cannot predict the impact future changes~~ in ~~accounting~~revenue ~~standards~~from orproducer ~~practices~~services ~~may~~operations, ~~have~~driven onby ~~public~~higher ~~companies~~prices in($19 ~~general~~million) orand ~~the~~higher ~~energy~~volumes ~~industry~~($46 ~~or on its operations specifically~~million). ~~New~~This ~~accounting~~increase ~~standards~~includes ~~could~~higher begas ~~issued~~sales byto ~~the~~another ~~FASB~~Dominion orsubsidiary, ~~the~~as ~~SEC~~part ~~that~~of ~~could~~Dominion's ~~change~~enterprise-wide ~~the~~price ~~way~~risk ~~the Company records revenue, expenses, assets and liabilities~~management. ~~These~~See ~~changes~~Note in15 ~~accounting~~to ~~standards could adversely affect~~ the ~~Company's~~Consolidated ~~reported~~Financial ~~earnings~~Statements; ~~or could increase reported liabilities.~~

~~Operating~~A ~~Segments~~$16 million increase in revenue from sales of purchased gas by exploration and production operations, incurred to facilitate gas transportation and other agreements. This increase in nonregulated gas sales sales revenue was largely offset by a corresponding increase in Purchased gas, net expense; and

~~Critical~~A ~~Accounting~~$9 ~~Policies~~million increase in revenue from nonregulated retail energy marketing operations, reflecting higher prices ($22 million), partially offset by lower volumes ($13 million).

~~Results~~ Gas oftransportation ~~Operations~~and storage revenue
increased 12% to $165 million, largely due to the third quarter 2003 reactivation of the Cove Point liquefied natural gas facility, which was acquired by the Company in September 2002.

	Net Income (Loss)		Operating Revenue		Operating Expenses
Three Months Ended September 30,	2003	2002	2003	2002	2003	2002
	(Millions)
Delivery	$ 3	$ (3)	$ 177	$ 132	$ 170	$ 125
Energy	36	42	493	318	433	252
Exploration & Production	77	63	402	331	267	222
Corporate and Other	(1)	11	5	1	4	6
Eliminations	-	-	(55)	(32)	(55)	(32)
Consolidated Total	$115	$113	$1,022	$ 750	$ 819	$ 573
Nine Months Ended September 30,
Delivery	$109	$ 91	$1,133	$ 796	$ 944	$ 637
Energy	156	147	1,638	1,015	1,372	774
Exploration & Production	236	174	1,224	963	807	653
Corporate and Other	(36)	6	15	1	43	10
Eliminations	-	-	(177)	(105)	(177)	(105)
Consolidated Total	$465	$418	$3,833	$2,670	$2,989	$1,969

Gas and oil production revenue increased 6% to $317 million primarily reflecting:

A $51 million increase in revenue recognized related to deliveries under VPP transactions; partially offset by

A $32 million decrease in revenue from gas production, primarily reflecting the sale of mineral rights under the VPP agreements.

Other revenue
increased 38% to $117 million, primarily reflecting:

A $16 million increase in sales of purchased oil by exploration and production operations, reflecting higher prices;

An $11 million increase in sales of extracted products, reflecting higher volumes; and

A $2 million increase in distribution operations' gathering service revenue, reflecting higher volumes.

Operating Expenses and Other Items

Purchased gas, net expense
increased 23% to $500 million, primarily reflecting:

A $69 million increase associated with producer services operations, driven by higher volumes ($44 million) and higher prices ($25 million), and

A $16 million increase related to purchases of gas by exploration and production operations incurred to facilitate gas transportation and other agreements, as discussed above in Nonregulated gas sales revenue.

The increase in purchased gas reflects gas purchases from another Dominion subsidiary. See Note 15 to the Consolidated Financial Statements.

Electric fuel and energy purchases expense
increased 138% to $88 million, primarily reflecting new business at the Company's nonregulated retail energy marketing operations. This increase includes energy purchases from another Dominion subsidiary. See Note 15 to the Consolidated Financial Statements.

Liquids, pipeline capacity and other purchases expense
increased 35% to $58 million, primarily reflecting an increase in the cost of oil purchased for resale.

PAGE 21

CONSOLIDATED NATURAL GAS COMPANY ~~ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS (Continued)~~

~~Consolidated~~ ITEM ~~Results~~2. ~~Overview~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS (Continued)

~~Total~~Other ~~operating revenue increased (36 percent), reflecting the recovery of higher purchased gas costs in regulated gas distribution~~ operations; ~~higher average prices~~ and ~~higher~~maintenance ~~volumes in retail sales operations; and higher average realized prices for sales of gas production, partially offset by lower average realized prices and lower production volumes for oil.~~expense
decreased 37% to $121 million, primarily reflecting the following:

~~Total~~A ~~operating~~$49 ~~expenses~~million ~~increased~~benefit ~~(43~~primarily ~~percent),~~due ~~reflecting~~to ~~higher~~favorable ~~average~~changes ~~prices~~ in ~~purchased~~the ~~gas~~fair ~~costs;~~value anof ~~increase~~certain oil options. As provided for in ~~purchased~~SFAS ~~volumes~~No. ~~associated~~133, ~~with~~Accounting for Derivative Instruments and Hedging Activities, the Company excludes changes in options's ~~nonregulated~~time ~~retail~~value ~~energy~~from ~~marketing~~its calculation of hedge effectiveness. Such amounts, as well as changes in the fair value of options not designated as hedges, are reported in other operations; ~~higher~~and ~~service~~maintenance ~~industry~~expenses. ~~costs~~During ~~related~~the period, the Company effectively settled certain options not designated as hedges by entering into offsetting option positions that had the effect of preserving approximately $42 million in mark-to-market ~~gas~~gains. Future gains and ~~oil~~losses ~~production;~~on ~~lower~~options ~~pension~~will ~~credits~~depend ~~and~~upon ~~higher~~the ~~other~~relationship ~~postretirement~~between ~~benefits.~~an option's cost and future commodity prices;

~~Consolidated~~A ~~Results~~$22 ~~Overview-Nine~~million ~~Months~~asset ~~Ended~~impairment ~~September~~charge 30recognized in the second quarter of 2003 related to the Company's generation facility in Kauai, Hawaii that was sold in December 2003. No comparable charge was recognized during 2004; and

~~Total~~A ~~operating~~$5 ~~revenue~~million ~~increased~~decrease ~~(44 percent), reflecting the recovery of higher purchased gas costs and the impact of comparably colder weather~~ in ~~the~~bad ~~first~~debt quarter of 2003 related to regulated gas distribution operations; higher average prices and higher volumes in retail sales operations; and comparably higher average realized prices for both gas and oil and higher volumes for gas productionexpense.

~~Total~~These ~~operating~~decreases ~~expenses~~were ~~increased~~partially ~~(52~~offset ~~percent),~~by ~~reflecting~~lower ~~higher~~net ~~volume~~pension ~~requirements,~~credits ~~primarily attributable to colder weather in the first quarter of 2003 in the franchise service areas; higher average prices~~ and higher ~~volumes~~other ~~associated~~postretirement ~~with~~benefit ~~the~~(OPEB) Company's nonregulated retail energy marketing operations; an impairment loss recognized in the second quarter of 2003 related to CNG International's Kauai investment classified as assets held for sale; higher severance taxes, service industry costs ~~and~~($8 ~~rate of depletion for gas and oil production; higher gross receipts taxes for regulated gas distribution operations; lower pension credits and higher other postretirement benefits~~million).

Other income ~~reflected an impairment loss recognized in the second quarter of 2003 related to CNG International's equity investment in Australian natural gas pipelines classified as assets held for sale.~~
increased $20 million, primarily reflecting an $8 million gain on the sale of a portion of CNGI's equity investment in an Australian pipeline business in the second quarter of 2004, as well as the impact of an $18 million impairment recognized in 2003 on this investment.

~~Segment~~Income ~~Results~~taxes
-The Company's effective tax rate increased by 1.1% to 38.3%, primarily as a result of an increase in the valuation allowance related to CNGI investments, partially offset by a reduction in state income taxes.

~~The~~Six ~~Delivery~~Months ~~segment~~Ended ~~and~~June ~~the~~30, ~~transmission~~2004 ~~business of the Energy segment are subject to cost-of-service rate regulation~~vs. Operating results can be affected by regulatory delays when price increases are sought through general rate filings to recover higher costs of operations. Weather is also an important factor since a major portion of the gas sold or transported by the distribution and transmission operations is ultimately used for space heating. 2003

Operating Revenue

Regulated gas sales revenue increased 15% to $843 million, largely resulting from a $147 million increase due to higher rates for regulated gas distribution operations primarily related to the recovery of higher gas prices, partially offset by a $54 million decrease associated with milder weather, lower industrial sales and customer migration to Energy Choice programs. The effect of this net increase in regulated gas sales revenue was largely offset by a comparable increase in Purchased gas expense.

Nonregulated electric sales revenue
increased 92% to $188 million, resulting primarily from customer growth in the Company's nonregulated retail energy marketing operations.

Nonregulated gas sales revenue
increased 36% to $1.1 billion primarily reflecting:

A $110 million increase in revenue from nonregulated retail energy marketing operations, driven by higher prices ($33 million) and higher volumes ($77 million); and

A $163 million increase in revenue from producer services operations, reflecting higher volumes ($199 million) and lower prices ($36 million). This increase includes higher gas sales to another Dominion subsidiary, as part of Dominion's enterprise-wide price risk management. See Note 15 to the Consolidated Financial Statements.

Gas transportation and storage
revenue increased 6% to $437 million, largely due to the third quarter 2003 reactivation of the Cove Point liquefied natural gas facility, which was acquired by the Company in September 2002.

PAGE 22

CONSOLIDATED NATURAL GAS COMPANY

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS
(Continued)

~~Delivery~~ Gas ~~Segment~~and oil production revenue increased 3% to $613 million primarily reflecting:

Selected Financial and Statistical Information	Three Months Ended September 30,		Nine Months Ended September 30,
	2003	2002	2003	2002
	(Millions)
Selected operating revenue:
Regulated gas sales	$120	$82	$851	$542
Gas transportation and storage	42	44	240	228
Other revenue	13	5	38	24
Selected operating expenses:
Purchased gas, net	$ 78	$40	$609	$330
Other operations and maintenance	58	51	192	175
Other taxes	15	16	85	76
Net income (loss) contribution	$ 3	$(3)	$109	$ 91
	(Billion Cubic Feet)
Throughput:
Gas sales	10	9	95	79
Gas transportation	31	34	171	165
Total throughput	41	43	266	244

An $80 million increase in revenue recognized related to deliveries under VPP transactions; partially offset by

~~Delivery~~A ~~Segment~~$59 ~~Results~~million decrease in revenue from gas production, primarily reflecting the sale of mineral rights under the VPP agreements.

The Delivery segment contributed $3 million to net income in the third quarter of 2003, as compared to a net loss of $3 million in the same quarter of 2002. The 2003 quarterly results reflected an increase in operating revenue, nearly offset by the effects of higher operating expenses.
The overall increase in operating revenue, primarily reflected increases in:
Regulated gas sales revenue

Other revenue
increased 24% to $223 million, primarily reflecting:

~~The~~A ~~overall~~$15 million increase in ~~operating~~sales ~~expenses~~of purchased oil by exploration and production operations, ~~primarily~~reflecting ~~reflected~~higher ~~increases~~prices; ~~in:~~

~~Purchased~~A ~~gas~~$17 ~~costs~~million increase in sales of extracted products, reflecting higher volumes; and

~~Other~~A $6 million increase in distribution operations' ~~and~~gathering ~~maintenance~~service ~~expense~~revenue, reflecting higher volumes.

~~Gas~~ Operating ~~sales~~Expenses ~~volumes increased 1 bcf~~ and ~~volumes~~Other ~~transported~~Items ~~decreased 3 bcf, as compared to 2002. Total throughput to industrial customers was 21 bcf in 2003, as compared to 24 bcf in 2002.~~

~~Delivery~~ Purchased ~~Segment~~gas, ~~Results~~net expense
increased 31% to $1.6 billion, primarily reflecting:

~~The~~An ~~Delivery segment contributed~~ $~~109~~86 million toincrease ~~net~~associated ~~income~~with innonregulated ~~the~~retail ~~nine~~energy ~~months ended September 30~~marketing, ~~2003,~~primarily asreflecting ~~compared to $91 million in the same period in 2002. The 2003 nine-month results reflected an increase in operating revenue, partially offset by the effects of~~ higher ~~operating~~volumes; ~~expenses.~~

A $154 million increase associated with producer services operations, reflecting higher volumes ($197 million), partially offset by lower prices ($43 million); and

An $88 million increase associated with regulated gas sales discussed above in Regulated gas sales revenue.

The increase in purchased gas expense reflects gas purchases from another Dominion subsidiary. See Note 15 to the Consolidated Financial Statements.

Electric fuel and energy purchases expense
increased 105% to $168 million, primarily reflecting new business at the Company's nonregulated retail energy marketing operations. This increase includes energy purchases from another Dominion subsidiary. See Note 15 to the Consolidated Financial Statements.

Liquids, pipeline capacity and other purchases expense
increased 14% to $109 million, primarily reflecting an increase in the cost of oil purchased for resale.

Other operations and maintenance expense decreased 28% to $273 million, primarily reflecting the following:

An $83 million benefit primarily due to favorable changes in the fair value of certain oil options as discussed previously;
A $22 million asset impairment charge recognized in 2003 related to the Company's generation facility in Kauai, Hawaii that was sold in December 2003. No comparable charge was recognized during 2004;
A $9 million decrease in bad debt expense; and

A $6 million charge recognized in 2003 related to severance costs for workforce reductions. No comparable charge was recognized during 2004.

These decreases were partially offset by lower net pension credits and higher OPEB costs ($15 million).

Depreciation, depletion and amortization expense
increased 6% to $308 million, primarily reflecting higher exploration and production finding and development costs and higher depreciation expense, resulting from property additions, including the consolidation of a VIE as a result of adopting FIN 46R at December 31, 2003.

Other income
increased $48 million, primarily reflecting an $8 million gain on the 2004 sale of a portion of CNGI's equity investment in an Australian pipeline business and an $18 million benefit resulting from a favorable adjustment to the carrying amount of this investment in 2004. In 2003, an $18 million impairment charge was recognized on this investment, based on estimated fair value at that time.

Cumulative effect of a change in accounting principle
-During the first quarter of 2003, the Company adopted SFAS No. 143, resulting in a net after-tax loss of $5 million.

PAGE 23

CONSOLIDATED NATURAL GAS COMPANY

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS
(Continued)

~~The~~Segment ~~overall~~Results ~~increase~~of ~~in operating revenue, primarily reflected increases in:~~Operations

Regulated gas sales revenue

Gas transportation revenue

Other revenue

The overall increase in operating expenses, primarily reflected increases in:

Purchased gas costs

Other operations and maintenance expense

Other taxes

Gas sales volumes increased 16 bcf and volumes transported increased 6 bcf, as compared to 2002. While the higher volumes in both sales and transport for residential and commercial customers reflected the impact of comparably colder weather in the first quarter of 2003, the transport volumes reflected a decrease in industrial activity. Total throughput to industrial customers was 75 bcf in 2003, as compared to 79 bcf in 2002.

Energy Segment

Selected Financial and Statistical Information	Three Months Ended September 30,		Nine Months Ended September 30,
	2003	2002	2003	2002
	(Millions)
Selected operating revenue:
Nonregulated electric sales	$ 67	$ 48	$ 155	$ 78
Nonregulated gas sales	296	149	1,051	545
Gas transportation and storage	116	101	372	338
Selected operating expenses:
Purchased gas, net	$300	$143	$1,017	$510
Electric fuel and energy purchases	57	41	132	67
Other operations and maintenance	44	35	124	106
Net income contribution	$ 36	$ 42	$ 156	$147
	(Billion Cubic Feet)
Throughput:
Gas sales	56	41	179	148
Gas transportation	104	103	444	412

The Energy segment includes the Company's gas transmission pipeline and storage system, certain gas production operations, a liquefied natural gas (LNG) import and storage facility and producer services operations that include aggregation of gas supply and related wholesale activities.

	Three Months Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
	(millions)
Net income contribution	$38	$40	$121	$121
Gas sales (bcf)	59	51	127	97
Gas transmission throughput (bcf)	107	94	423	361

__________________

bcf = billion cubic feet

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

	Three Months Ended June 30,	Six Months Ended June 30,
	2004 vs. 2003 Increase (Decrease)	2004 vs. 2003 Increase (Decrease)
	(millions)

Gas prices	$(1)	$5
Cove Point LNG operations	2	5
Operations and maintenance expense	(6)	(9)
Other	3	(1)
Change in net income contribution	$(2)	$ -

The Energy segment's net income decreased $2 million and remained unchanged for the three and six months ended June 30, 2004, respectively, as compared to the same periods of 2003, primarily reflecting the following:

Lower gas prices in the second quarter and higher gas prices in the first six months on producer services operations;

A higher contribution from the Cove Point liquefied natural gas facility due to a full three and six months of operations; and

Higher operations and maintenance expense due to lower net pension credits and increased OPEB costs and higher contractor services expense.

PAGE 24

CONSOLIDATED NATURAL GAS COMPANY

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS
(Continued)

Delivery Segment

~~Energy~~The ~~Segment~~Delivery ~~Results~~segment includes the Company's regulated gas distribution and customer service business and nonregulated retail energy marketing operations and related products and services.

The Energy segment contributed $36 million to net income in the third quarter of 2003, as compared to $42 million in the same period in 2002. The 2003 quarterly results reflected an increase in operating revenue, offset by the effects of higher operating expenses.

	Three Months Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
	(millions)
Net income contribution	$28	$11	$127	$103
Throughput:
Gas sales-regulated (bcf)	16	18	78	85
Gas transportation-regulated (bcf)	46	40	144	140
Total throughput (bcf)	62	58	222	225

~~The~~ Presented ~~overall~~below, ~~increase~~on inan ~~operating~~after-tax ~~revenue~~basis, ~~primarily~~are ~~reflected~~the ~~increases~~key infactors impacting the Delivery segment's operating results:

Nonregulated electric sales revenue

	Three Months Ended June 30,	Six Months Ended June 30,
	2004 vs. 2003 Increase (Decrease)	2004 vs. 2003 Increase (Decrease)
	(millions)

Weather	$ (1)	$(8)
Nonregulated retail energy marketing operations	2	16
Other margins	6	8
Pension and OPEB expense	(3)	(7)
Bad debt expense	5	11
Other	8	4
Change in net income contribution	$17	$24

The Delivery segment's net income increased $17 million and $24 million for the three and six months ended June 30, 2004, respectively, as compared to the same periods of 2003, primarily reflecting the following:

~~Nonregulated~~Lower regulated gas sales ~~revenue~~attributable to comparably warmer weather;

~~Gas~~Higher ~~transportation~~contributions from nonregulated retail energy marketing operations, primarily reflecting an increase in customer accounts and ~~storage~~increased ~~revenue~~margins;

~~The~~Higher ~~overall~~contributions from regulated gas operations, reflecting an increase in ~~operating~~production ~~expenses~~and gathering revenue, ~~primarily~~higher ~~reflected~~industrial ~~increases~~sales ~~in:~~and transport revenue and lower purchased gas prices;

~~Purchased~~Lower ~~gas~~net pension credits and an increase in OPEB costs; and

~~Electric~~Lower ~~fuel~~bad debt expenses, reflecting the effect of the bad debt rider for Ohio customers that allows for the deferral and ~~energy~~subsequent ~~purchases~~recovery of incremental bad debt expense over the level that is included in base rates. The six month period also reflects increased reserves required in the first quarter of 2003 due to colder than normal weather.

Other operations and maintenance expense

Energy Segment Results

The Energy segment contributed $156 million to net income in the nine months ended September 30, 2003, as compared to $147 million in the same period in 2002. The 2003 nine-month results reflected an increase in operating revenue, partially offset by the effects of higher operating expenses.

The overall increase in operating revenue, primarily reflected increases in:

Nonregulated electric sales revenue

Nonregulated gas sales revenue

Gas transportation and storage revenue

The overall increase in operating expenses, primarily reflected increases in:

Purchased gas costs

Electric fuel and energy purchases

Other operations and maintenance expense

PAGE 25

CONSOLIDATED NATURAL GAS COMPANY

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS
(Continued)

Exploration & Production Segment

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

Selected Financial and Statistical Information	Three Months Ended September 30,		Nine Months Ended September 30,
	Three Months Ended June 30,		Six Months Ended June 30,
	2003	2002	2003	2002
	2004	2003	2004	2003
	(Millions, except average price amounts)
	(millions)
Selected operating revenue:
Net income contribution	$144	$75	$253	$159
Gas and oil production	$ 325	$ 265	$ 987	$ 761
Gas production (bcf)	67.0	70.9	136.6	140.4
Other revenue	53	48	163	140
Oil production (million bbls)	2.1	2.0	4.0	4.0
Selected operating expenses:
Average realized prices with hedging results:
Purchased gas, net	$ 29	$ 17	$ 97	$ 59
Gas (per mcf)(1)	$4.05	$4.22	$4.07	$4.25
Other operations and maintenance	66	51	199	145
Oil (per bbl)	$25.24	$24.70	$24.78	$25.41
Depreciation, depletion and amortization	114	106	331	305
Average realized prices without hedging results:
Other taxes	18	9	58	30
Gas (per mcf)(1)	$5.67	$5.27	$5.57	$5.72
Net income contribution	$ 77	$ 63	$ 236	$ 174
Oil (per bbl)	$37.40	$28.41	$35.78	$31.07
Average realized prices with hedging results:
Other information:
Gas (per mcf)(1)	$ 4.10	$ 3.57	$ 4.20	$ 3.53
DD&A (unit of production rate per mcfe)	$1.37	$1.34	$1.36	$1.30
Oil (per bbl)	$24.54	$24.85	$25.13	$23.37
Average prices without hedging results:
Gas (per mcf)(1)	$ 4.90	$ 3.17	$ 5.45	$ 2.99
Oil (per bbl)	$29.95	$27.17	$30.70	$24.38
Gas production (bcf)	70	69	210	200
Oil production (million bbls)	1.9	2.0	5.9	6.5

~~________________~~_____________________ bbl = barrel mcf = thousand cubic feet | mcfe = thousand cubic feet equivalent

~~bbl~~ (1) ~~= barrel~~

Excludes $51 million and $80 million of revenue recognized in the three and six months ended June 30, 2004, respectively, under the VPP agreements described in Note 8 to the Consolidated Financial Statements and Note 10 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2003.

~~bcf~~ Presented =below, ~~billion~~on ~~cubic~~an ~~feet~~after-tax basis, are the key factors impacting the Exploration & Production segment's operating results:

mcf = thousand cubic feet

	Three Months Ended June 30,	Six Months Ended June 30,
	2004 vs. 2003 Increase (Decrease)	2004 vs. 2003 Increase (Decrease)
	(millions)

VPP revenue	$32	$50
Gas and oil-production	(11)	(16)
Gas and oil-prices	(4)	(11)
Operations and maintenance expense	30	57
DD&A-production	3	3
DD&A-rate	(3)	(8)
Income taxes	20	20
Other	2	(1)
Change in net income contribution	$ 69	$ 94

(1) Excludes $14 million of revenue recognized for the three and nine months ended September 30, 2003 under the volumetric production payment agreement as described in Note 15 to the Consolidated Financial Statements.

Exploration & Production Segment Results

The Exploration & Production segment contributed $77 million to net income in the third quarter of 2003, as compared to $63 million in the same quarter of 2002. The Exploration & Production segment contributed $236 million to net income in the nine months ended September 30, 2003, as compared to $174 million in the same period in 2002.

Gas and oil production revenue increased for the third quarter of 2003, primarily due to higher average realized prices for gas, partially offset by lower average realized prices and lower production volumes for oil. Gas and oil production revenue increased for the nine months ended September 30, 2003, primarily due to higher average realized prices for both gas and oil, as well as higher gas production volumes. Other revenue increased for the nine months ended September 30, 2003, primarily due to higher average realized prices for extracted by-products and brokered oil sales.

PAGE 26

CONSOLIDATED NATURAL GAS COMPANY

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS
(Continued)

The Exploration & Production segment's net income increased $69 million and $94 million for the three and six months ended June 30, 2004, respectively, as compared to the same periods of 2003, primarily reflecting the following:

~~The~~Recognition ~~overall~~of ~~increase~~revenue in ~~operating~~connection ~~expenses~~with ~~for~~deliveries ~~the~~under ~~third~~VPP ~~quarter~~agreements; ~~and nine months ended September 30, 2003, primarily reflected increases in:~~

~~Purchased~~Lower gas ~~costs~~production reflecting the sale of mineral rights under VPP agreements, which was partially offset by increased gas production from various locations;

~~Other~~Higher ~~operations~~oil ~~and~~production ~~maintenance~~reflecting ~~expense~~the beginning of production related to the deepwater Gulf of Mexico Devils Tower project;

~~Depreciation~~Lower operations and maintenance expenses, ~~depletion~~which decreased primarily due to favorable changes in the fair value of certain oil options. Future gains and ~~amortization~~losses ~~expense~~on options will depend upon the relationship between an option's cost and future commodity prices;

~~Other~~A ~~taxes~~higher rate for depreciation, depletion and amortization (DD&A), primarily reflecting higher industry finding and development costs, a reduction in production volumes associated with the VPP transactions, and increased acquisition costs; and

~~Corporate~~Lower state income taxes as a result of updated estimates for the 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 ~~Other~~the ~~Segment~~volume of business transactions.

Corporate and Other

	Three Months Ended September 30,		Nine Months Ended September 30,
	2003	2002	2003	2002
	(Millions)
Net income (loss)	$(1)	$11	$(36)	$6

Corporate and Other also includes CNGI and other minor subsidiaries.

Presented below are the Corporate and Other ~~Segment~~segment's ~~Results~~after-tax operating results for the three and six months ended June 30, 2004 and 2003:

The Corporate and Other segment reported a net loss of $1 million in the third quarter of 2003, as compared to net income of $11 million for the same quarter in 2002. The quarterly net income in 2002 reflected the net effect, allocated to the Company, of including certain subsidiaries in Dominion's consolidated state income tax returns.

	Three Months Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
	(millions)
Net loss	$ (28)	$ (23)	$ (8)	$ (33)

~~Corporate~~ Three ~~and~~Months ~~Other~~Ended ~~Segment~~June ~~Results~~30, 2004 vs. 2003

~~The~~Corporate and Other experienced a net loss of $28 million for ~~the~~2004, ~~Corporate~~compared ~~and~~to ~~Other~~a ~~segment~~net ~~was~~loss of $3623 million in ~~the~~2003. ~~nine~~The ~~months~~2004 ~~ended~~results ~~September~~primarily ~~30,~~reflect ~~2003,~~an asincrease ~~compared~~in an income tax valuation allowance related to ~~net~~CNGI ~~income~~investments, ofpartially offset by an $68 million ~~for~~gain on the ~~same~~sale ~~period~~of a portion of CNGI's investment in ~~2002~~an Australian pipeline business in June 2004. The 2003 ~~nine-month~~ net loss ~~reflected:~~primarily reflects impairment losses totaling $40 million ($25 million after-tax) related primarily to CNGI's investments in the Australian pipeline business and a small generation facility in Kauai, Hawaii that was sold in December 2003.

a Six ~~$40~~Months ~~million~~Ended ~~($25~~June ~~million~~30, ~~after-tax)~~2004 ~~impairment~~vs. ~~loss related to certain CNG International investments classified as assets held for sale (see Note 7 to the Consolidated Financial Statements);~~2003

Corporate and Other experienced a net loss of $78 million (for 2004, compared to a net loss of $433 million ~~after-~~in 2003. The 2004 results reflect an additional tax) ~~charge~~valuation ofallowance ~~severance~~recorded ~~costs~~in the second quarter of 2004 related to ~~workforce~~certain ~~reductions,~~CNGI ~~including~~investments $4classified ~~million~~as held for sale, partially offset by an $28 million gain on the sale of a portion of CNGI's investment in an Australian pipeline business and an $118 million ~~attributable~~benefit tofrom adjusting the ~~Energy,~~carrying ~~Delivery~~amount ~~and~~of ~~Exploration~~this &investment ~~Production~~in ~~segments,~~the ~~respectively;~~first ~~and~~quarter to its then current estimate of fair value.

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 (see Note 3 to the Consolidated Financial Statements) which was attributed to the Energy segment.

Contractual Obligations

PAGE 27

CONSOLIDATED NATURAL GAS COMPANY ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS (Continued)

The 2003 net loss primarily reflects impairment losses totaling $40 million ($25 million after-tax) related primarily to investments in the Australian pipeline business and a small generation facility in Kauai, Hawaii that was sold in December 2003. In addition, the following specific items attributable to operating segments contributed to the 2003 net loss:

~~ITEM~~A 2$5 million after-tax loss associated with the cumulative effect of a change in accounting principle related to the adoption of SFAS No. ~~MANAGEMENT'S~~143 ~~DISCUSSION~~on ~~AND~~January ~~ANALYSIS~~1, OF2003 ~~RESULTS~~attributable OFto ~~OPERATIONS (Continued)~~the Energy segment; and

~~Future~~A ~~Issues~~$6 million ($4 million after-tax) charge for severance costs related to workforce reductions 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 gross credit exposure as of June 30, 2004 for these activities. The credit exposure amounts exclude amounts receivable from affiliated companies. 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.

Regulated Gas Distribution Operations

	Gross Credit Exposure	Credit Collateral	Net Credit Exposure
	(millions)
Investment grade⁽¹⁾	$178	$1	$177
Non-investment grade⁽²⁾	15	-	15
No external ratings:
Internally rated-investment grade⁽³⁾	45	-	45
Internally rated-non-investment grade⁽⁴⁾	201	-	201
Total	$439	$1	$438

~~Rate Matters~~_______________

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 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 three-month 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.(

1) Designations as investment grade are based on minimum credit ratings assigned by Moody's and 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 2% of the total gross credit exposure.
(3) The five largest counterparty exposures, combined, for this category represented approximately 6% of the total gross credit exposure.
(4) The five largest counterparty exposures, combined, for this category represented approximately 10% of the total gross credit exposure.

In August 2003, the Company filed an application with the West Virginia Public Service Commission (the West Virginia Commission) to increase its purchased gas cost rate by approximately $31 million on an annualized basis, effective for the period January 1, 2004 through October 31, 2004. The increase is in anticipation of higher purchased gas costs expected for that period. Because the Company's existing rate moratorium will expire at the end of 2003, the application reflects a return to the traditional purchase gas adjustment treatment for the Company's purchased gas costs. The West Virginia Commission is expected to issue an order setting an interim rate in the fourth quarter of 2003, with a final rate order to be issued in early 2004.

Other

Accounting Matters

PAGE 28

CONSOLIDATED NATURAL GAS COMPANY ITEM 42. ~~CONTROLS~~MANAGEMENT'S DISCUSSION AND ~~PROCEDURES~~ANALYSIS OF RESULTS OF OPERATIONS (Continued)

Risk Factors and Cautionary Statements That May Affect Future Results

~~Senior~~Factors ~~management,~~that ~~including~~may ~~the~~cause ~~Chief~~actual ~~Executive~~results ~~Officer~~to ~~and~~differ ~~Chief~~materially ~~Financial~~from ~~Officer,~~those ~~evaluated~~indicated ~~the~~in ~~effectiveness~~any offorward-looking ~~the~~statement ~~Company's~~include ~~disclosure~~weather ~~controls~~conditions; ~~and~~governmental ~~procedures~~regulations; ascost of ~~the~~environmental ~~end~~compliance; offluctuations ~~the~~in ~~period~~energy-related ~~covered~~commodities byprices ~~this~~and ~~report.~~the ~~Based~~effect these could have on ~~this~~the ~~evaluation~~Company's ~~process~~earnings, liquidity position and the ~~Chief~~underlying ~~Executive~~value ~~Officer~~of ~~and~~its ~~Chief~~assets; ~~Financial~~trading ~~Officer~~counterparty ~~have~~credit ~~concluded~~risk; ~~that~~capital ~~the~~market ~~Company's~~conditions, ~~disclosure~~including ~~controls~~price risk due to marketable securities held as investments in trusts and ~~procedures~~benefit ~~are~~plans; ~~effective.~~fluctuations ~~There~~in ~~were~~interest norates; changes in ~~the~~rating ~~Company's~~agency ~~internal~~requirements ~~control~~and ~~over~~ratings; ~~financial~~changes ~~reporting~~in ~~that~~accounting ~~occurred~~standards; ~~during~~collective bargaining agreements and labor negotiations; the ~~last~~risks ~~fiscal~~of ~~quarter~~operating ~~that~~businesses ~~have~~in ~~materially~~regulated ~~affected,~~industries orthat are ~~reasonably~~becoming ~~likely~~deregulated; topolitical ~~materially~~and ~~affect,~~economic ~~the~~conditions ~~Company's~~(including ~~internal~~inflation ~~control~~and ~~over~~deflation). ~~financial~~Other ~~reporting.~~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, disrupting operations, causing production delays and unusual maintenance and repair that require the Company to incur additional expenses.

The Company is subject to complex governmental 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
. 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.
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.

PAGE 29

CONSOLIDATED NATURAL GAS COMPANY ~~PART~~ ITEM II2. -MANAGEMENT'S ~~OTHER~~DISCUSSION ~~INFORMATION~~AND ANALYSIS OF RESULTS OF OPERATIONS (Continued)
~~In 1999, a class action was filed by Quinque Operating Co. and other parties against approximately 300 defendants, including the Company and three of its subsidiaries, in Stevens County, Kansas.~~ The complaint seeks damages for alleged fraud, misrepresentation, conversion and assorted other claims in the measurement and payment of gas royalties from privately held gas leases. Quinque Operating Co. dropped out of the case and Will Price, a gas royalty owner based in Kansas, assumed the lead plaintiffCompany's ~~role.~~exploration ~~The~~and ~~defendants'~~production ~~motion~~business tois ~~deny~~dependent ~~class~~on ~~certification~~factors ~~was~~that ~~granted~~cannot inbe ~~April~~predicted ~~2003.~~or ~~In June 2003, the Company defendants were dropped from suit~~controlled. ~~The deadline to file an amended complaint has expired and this matter is now considered closed.~~
Factors that may affect the Company's financial results include fluctuations in natural gas and crude oil prices, results of future drilling and well completion activities, the Company's ability to acquire additional land positions in competitive lease areas as well as inherent operational risks that could disrupt production. The Company's liquidity may also be impacted by margin requirements that result from financial derivatives used to hedge future sales of gas and oil production and require the deposit of funds or other collateral with counterparties to cover the fair value of covered contracts in excess of agreed-upon credit limits. Short-term market declines in natural gas and oil prices may also result in the permanent write-down of the Company's 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), in a given country, 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 and its subsidiaries 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 June 30, 2004, the Company's senior unsecured debt was 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 modify 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.

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

PAGE 30

CONSOLIDATED NATURAL GAS COMPANY

ITEM 4. 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 and, as a result, has included in its consolidated financial statements those SPEs described in Note 3 to the Consolidated Financial Statements in its Annual Report on Form 10-K for the year ended December 31, 2003. The Consolidated Balance Sheet as of June 30, 2004 reflects $219 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 or internal control over financial reporting in place at these entities.

PAGE 31

CONSOLIDATED NATURAL GAS COMPANY
PART II. OTHER INFORMATION

ITEM 1. 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 and its subsidiaries, 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.

ITEM 5. OTHER INFORMATION

Other FERC Matter

The Company and the Federal Energy Regulatory Commission (FERC) have reached a settlement of a self-reported infraction of FERC regulations involving data sharing of non-public gas storage information. Under the settlement, the Company will pay a $500,000 civil penalty, refund $4.5 million to its non-affiliated natural gas storage customers and enhance internal training and oversight of employees who handle non-public, market-sensitive data. The Company has previously accrued the amounts to be paid pursuant to the settlement agreement.

Statoil ASA (Statoil) Agreement

In June 2004, the Company executed 20-year contracts with Statoil for the increased capacity planned for its Cove Point liquefied natural gas facility and related gas transmission services. Under the terms of the agreements, Statoil will purchase firm LNG tanker discharge services and related transportation service from Cove Point, as well as downstream firm transportation and storage services from Dominion Transmission, Inc. Plans call for increasing the Cove Point storage tank capacity to 14.6 bcf and the plant's deliverability by 0.8 bcf per day to a total of 1.8 bcf per day. To provide the transmission services, the Company also plans to expand its pipeline originating at Cove Point to deliver more natural gas to interstate pipeline connections in the mid-Atlantic region as well as to build a pipeline and two compressor stations in central Pennsylvania. These projects are subject to regulatory approval and are expected to be placed in service in 2008.

Rate Matters - Gas Distribution

In July 2004, the Pennsylvania Public Utility Commission (PUC) 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 PUC 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.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) 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 (filed herewith).
	10.1	$1,500,000,000 3-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 (filed herewith).
	10.1	$1,250,000,000 364-Day Credit Agreement among Dominion Resources, Inc., Virginia Electric and Power Company, Consolidated Natural Gas Company and JPMorgan Chase Bank, as Administrative Agent for the Lenders, dated as of May 29, 2003 (filed herewith).
	10.2	$1,000,000,000 364-Day Credit Agreement among Consolidated Natural Gas Company and Barclays Bank PLC, as Administrative Agent for the Lenders, dated as of August 20, 2003 (filed herewith).

~~CONSOLIDATED~~PAGE ~~NATURAL GAS COMPANY PART II. - OTHER INFORMATION~~32

(a) Exhibits (continued):
12 Ratio of earnings to fixed charges (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).
99 Condensed consolidated earnings statements (unaudited) (filed herewith).
CONSOLIDATED NATURAL GAS COMPANY
PART II. OTHER INFORMATION

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits (continued):
	12	Ratio of earnings to fixed charges (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 (filed herewith).
	99	Condensed consolidated earnings statements (unaudited) (filed herewith).

(b) Reports on Form 8-K:

There were no reports on Form 8-K filed during the quarter ended June 30, 2004.

There were no reports on Form 8-K filed during the quarter ended September 30, 2003.
SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	CONSOLIDATED NATURAL GAS COMPANY Registrant
November 7, 2003	/s/ Steven A. Rogers
August 4, 2004	/s/ Steven A. Rogers
	Steven A. Rogers Vice President and Controller (Principal Accounting Officer)

	Accumulated Other Comprehensive Loss After-Tax	Portion Expected to be Reclassified to Earnings During the Next 12 Months	Maximum Term
	(Millions)
Commodities	$(449)	$(172)	53 months
Interest Rate	(17)	(1)	123 months
Total	$(466)	$(173)

	Amount
	(Millions)
Asset retirement obligations at January 1, 2003	$ -
Asset retirement obligations recognized in transition	198
Asset retirement obligations incurred during the period	2
Asset retirement obligations settled during the period	(6)
Accretion expense	7
Revisions in estimated cash flows	(1)
Asset retirement obligations at September 30, 2003	$200

At September 30, 2003	Credit Exposure (Millions)
Investment grade(1)	$129
Non-investment grade(2)	11
No external ratings:
Internally rated-investment grade(3)	39
Internally rated-non-investment grade(4)	90
Total	$269

(a) Exhibits (continued):
	12	Ratio of earnings to fixed charges (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).
	99	Condensed consolidated earnings statements (unaudited) (filed herewith).

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