CONSOLIDATED NATURAL GAS CO/VA - 10-Q Quarterly Report

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

____________

FORM 10-Q
____________

(Mark one)

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

or

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

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 September 30, 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.

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CONSOLIDATED NATURAL GAS COMPANY

INDEX

		Page Number
PART I. Financial Information
Item 1	Consolidated Financial Statements
	Consolidated Statements of Income - Three and Nine Months Ended September 30, 2004 and 2003		3
	Consolidated Balance Sheets - September 30, 2004 and December 31, 2003		4
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2004 and 2003		6
	Notes to Consolidated Financial Statements		7
Item 2	Management's Discussion and Analysis of Results of Operations		16
Item 4	Controls and Procedures		29
	PART II. Other Information
Item 1	Legal Proceedings		30
Item 6	Exhibits		30

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CONSOLIDATED NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

	Three Months Ended September 30,		Nine Months Ended September 30,
	2004	2003	2004	2003
	(millions)

Operating Revenue
External customers	$1,031	$ 824	$3,812	$3,350
Affiliated customers	217	198	815	483
Total operating revenue	1,248	1,022	4,627	3,833

Operating Expenses
Purchased gas, net
External suppliers	280	194	1,565	1,093
Affiliated suppliers	107	159	386	454
Electric fuel and energy purchases
External suppliers	46	29	123	84
Affiliated suppliers	55	31	146	58
Liquids, pipeline capacity and other purchases	98	41	207	137
Other operations and maintenance
Other	219	131	412	425
Affiliated	43	37	123	121
Depreciation, depletion and amortization	156	152	464	442
Other taxes	55	45	191	175
Total operating expenses	1,059	819	3,617	2,989

Income from operations	189	203	1,010	844

Other income	3	10	43	2

Interest and related charges:
Interest expense-junior subordinated notes payable to affiliated trust	4	-	12	4
Interest expense - other	38	32	113	103
Distributions-mandatorily redeemable trust preferred securities	-	4	-	8
Total interest and related charges	42	36	125	115

Income before income taxes	150	177	928	731
Income tax expense	50	62	335	261
Income before cumulative effect of a change in accounting principle	100	115	593	470
Cumulative effect of a change in accounting principle (net of income taxes of $3)	-	-	-	(5)

Net income	$ 100	$ 115	$ 593	$ 465

____________

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

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CONSOLIDATED NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)

	September 30, 2004	December 31, 2003⁽¹⁾
	(millions)
ASSETS
Current Assets
Cash and cash equivalents	$ 28	$ 39
Customer accounts receivable (net of allowance of $25 in 2004 and $37 in 2003)	620	795
Other accounts receivable	49	45
Receivables due from affiliates	340	340
Inventories	306	238
Prepayments	53	56
Derivative assets	454	106
Margin deposit assets	60	59
Other	471	237
Total current assets	2,381	1,915

Investments
Investment in affiliates	210	203
Other	82	79
Total investments	292	282

Property, Plant and Equipment
Property, plant and equipment	16,871	15,854
Accumulated depreciation, depletion and amortization	(6,070)	(5,674)
Net property, plant and equipment	10,801	10,180
Deferred Charges and Other Assets
Goodwill, net	623	626
Regulatory assets	366	328
Prepaid pension cost	956	872
Derivative assets	434	84
Other	216	210
Total deferred charges and other assets	2,595	2,120

Total assets	$16,069	$14,497

________________

^{(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, 2004	December 31, 2003⁽¹⁾
	(millions)
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities
Securities due within one year	$ 550		$ 501
Short-term debt	-		151
Accounts payable, trade	743		655
Payables to affiliates	126		118
Affiliated current borrowings	690		1,027
Accrued interest, payroll and taxes	206		214
Derivative liabilities	1,563		620
Other	361		278
Total current liabilities	4,239		3,564

Long-Term Debt
Long-term debt	3,053		3,213
Junior subordinated notes payable to affiliated trust	206		206
Total long-term debt	3,259		3,419

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits	2,146		1,760
Asset retirement obligations	243		240
Derivative liabilities	1,442		669
Regulatory liabilities	217		212
Other	418		268
Total deferred credits and other liabilities	4,466		3,149
Total liabilities	11,964		10,132

Commitments and Contingencies (see Note 10)

Common Shareholder's Equity
Common stock-no par value, 100 shares authorized and outstanding	1,816		1,816
Other paid-in capital	2,479		2,478
Retained earnings	860		608
Accumulated other comprehensive loss	(1,050)		(537)
Total common shareholder's equity	4,105		4,365

Total liabilities and shareholder's equity	$16,069		$14,497

________________

^{(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 6
CONSOLIDATED NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)}

	Nine Months Ended September 30,
	2004	2003
	(millions)
Operating Activities
Net income	$ 593	$ 465
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	464	442
Deferred income taxes and investment tax credits, net	354	146
Valuation adjustment on CNG International assets	(18)	-
Cumulative effect of a change in accounting principle, net of income taxes	-	5
Changes in:
Accounts receivable	171	122
Affiliated receivables and payables	8	(161)
Inventories	(68)	(207)
Prepayments	3	75
Margin deposit assets and liabilities	(1)	37
Deferred purchased gas costs, net	15	(77)
Accounts payable, trade	88	14
Accrued interest, payroll and taxes	(8)	47
Other operating assets and liabilities	(69)	(65)
Net cash provided by operating activities	1,532	843

Investing Activities
Additions to gas and oil properties, including acquisitions	(857)	(855)
Proceeds from sales of gas and oil properties	413	290
Plant construction and other property additions	(234)	(285)
Other	46	(4)
Net cash used in investing activities	(632)	(854)

Financing Activities
Repayment of short-term debt, net	(151)	(197)
Issuance (repayment) of affiliated current borrowings, net	(337)	710
Repayment of long-term debt	(88)	(151)
Common stock dividend payments	(341)	(316)
Other	6	-
Net cash (used in) provided by financing activities	(911)	46

Increase (decrease) in cash and cash equivalents	(11)	35
Cash and cash equivalents at beginning of period	39	22
Cash and cash equivalents at end of period	$ 28	$ 57

Supplemental Cash Flow Information
Noncash transaction from financing activities:
Conversion of short-term borrowings from parent to paid-in capital	$ -	$ 600

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

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Nature of Operations

Consolidated Natural Gas Company (the Company), a public utility holding company registered under the Public Utility Holding Company Act of 1935 (1935 Act), is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion). The Company, through its subsidiaries, operates in all phases of the natural gas business, explores for and produces gas and oil and provides a variety of energy marketing services. Its regulated gas distribution subsidiaries serve approximately 1.7 million residential, commercial and industrial gas sales and transportation customer accounts in Ohio, Pennsylvania and West Virginia and its nonregulated retail energy marketing businesses serve approximately 1.3 million residential and commercial gas and electric customer accounts in the Northeast and Midwest. The Company operates an interstate gas transmission pipeline system in the Midwest, the Mid-Atlantic states and the Northeast and a liquefied natural gas (LNG) import and storage facility in Maryland. The Company's producer services operations involve the aggregation of natural gas supply and related wholesale activities. The Company's exploration and production operations are located in several major gas and oil producing basins in the United States, both onshore and offshore.

The Company manages its daily operations through three primary operating segments: Energy, Delivery and Exploration & Production. In addition, the Company reports its corporate functions as a segment. Assets remain wholly-owned by the Company's legal 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, 2003 and the Quarterly Reports on Form 10-Q for the quarters ended March 31, 2004 and June 30, 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 30, 2004, its results of operations for the three and nine months ended September 30, 2004 and 2003, and its cash flows for the nine months ended September 30, 2004 and 2003.

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

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

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.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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 2003 Consolidated Financial Statements have been reclassified to conform to the 2004 presentation.

Note 3. Recently Adopted Accounting Standards

2004

FSP FAS 142-2

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

FIN 46R

The Company adopted FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, (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.

As described more fully in Note 3 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2003, the Company adopted FIN 46R for its interests in special purpose entities on December 31, 2003.

2003

SFAS No. 143

Effective January 1, 2003, the Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations, which provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Upon adoption, the Company recognized a $5 million after-tax loss as the cumulative effect of this change in accounting principle.

Note 4. Recently Issued Accounting Standards

SAB 106

In September 2004, the SEC issued Staff Accounting Bulletin No. 106 (SAB 106) that provides guidance to oil and gas companies following the full cost accounting method regarding the application of SFAS 143. SAB 106 requires companies calculating the full cost ceiling test to exclude future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet as required by SFAS 143. However, estimated dismantlement and abandonment costs related to future development activities, which are not required to be accrued under SFAS 143, should continue to be included in the full cost ceiling test. The SEC staff has also recommended that companies discuss how the adoption of SFAS 143 has affected their accounting for oil and gas operations. The accounting and disclosure requirements of SAB 106 are to be applied prospectively beginning with the first quarter of 2005. The Company is currently evaluating the impact, if any, that SAB 106 may have on it s calculations under the full cost ceiling test.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 5. Operating Revenue

The Company's operating revenue consists of the following:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2004	2003	2004	2003
	(millions)
Operating Revenue
Regulated gas sales	$ 110	$ 120	$ 953	$ 851
Nonregulated electric sales	115	72	303	170
Nonregulated gas sales
External customers	146	131	656	664
Affiliated customers	206	179	770	439
Gas transportation and storage	155	145	593	559
Gas and oil production	350	295	963	890
Other	166	80	389	260
Total operating revenue	$1,248	$1,022	$4,627	$3,833

Note 6. Comprehensive Income

The following table presents total comprehensive income:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2004	2003	2004	2003
	(millions)

Net income	$100	$115	$593	$465
Other comprehensive income (loss):
Net other comprehensive income (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	(230)	149	(480)	(169)
Other⁽¹⁾	(1)	(22)	(33)	(4)
Other comprehensive income (loss)	(231)	127	(513)	(173)
Total comprehensive income (loss)	$(131)	$ 242	$ 80	$ 292

________________

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

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 7. Hedge Accounting Activities

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	(millions)
	2004	2003	2004	2003
Portion of losses on hedging instruments determined to be ineffective and included in net income:
Fair value hedges	$ (1)	$(2)	$ (1)	$ (1)
Cash flow hedges	(1)	-	-	-
Net ineffectiveness	$ (2)	$(2)	$ (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)
Cash flow hedges	$ 30	$ (3)	$ 104	3
Total change in options' time value	$ 30	$ (3)	$ 104	$ 2

The following table presents selected information related to cash flow hedges included in accumulated other comprehensive loss in the Consolidated Balance Sheet at September 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	$ (707)	$(374)	41 months
Oil	(342)	(151)	39 months
Interest Rate	(1)	-	42 months
Total	$(1,050)	$(525)

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.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

As a result of damage to certain offshore production facilities in the Gulf of Mexico caused by Hurricane Ivan, and the related loss of forecasted oil production for the period from mid-September 2004 to May 2005, the Company discontinued certain cash flow hedges effective September 14, 2004. In connection with the discontinuance of these cash flow hedges, the Company reclassified losses of $71 million from accumulated other comprehensive loss to earnings during the three months ended September 30, 2004.

Note 8. 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 September 30, 2004.

Note 9. Significant Financing Transactions

Credit Facilities

In June 2004, the Company entered into a $100 million letter of credit agreement that terminates in June 2007. In August 2004, the Company entered into a $100 million letter of credit agreement that terminates in August 2009. These agreements support letter of credit issuances, providing collateral required on derivative financial contracts used by the Company in its risk management strategies for gas and oil production. At September 30, 2004, outstanding letters of credit under these agreements totaled $200 million.

In August 2004, the Company entered into a $1.5 billion three-year revolving credit facility that terminates in August 2007. This credit facility is being used to support the issuance of commercial paper and letters of credit to provide collateral required on derivative financial contracts used by the Company in its risk management strategies for gas and oil production. At September 30, 2004, outstanding letters of credit under this facility totaled $1.46 billion.

In October 2004, the Company entered into three letter of credit agreements totaling $700 million that terminate in April 2005. These agreements support letter of credit issuances, providing collateral required on derivative financial contracts used by the Company in its risk management strategies for gas and oil production.

Joint Credit Facilities and Short-Term Debt

Dominion, Virginia Power, a wholly-owned subsidiary of Dominion, and the Company have two three-year revolving joint credit facilities that allow aggregate borrowings of up to $2.25 billion. The facilities include a $1.5 billion credit facility that was entered into in May 2004 and terminates in May 2007 and a $750 million credit facility that was entered into in May 2002 and terminates in May 2005. These credit facilities are being used for working capital, as support for the combined commercial paper programs of Dominion, Virginia Power and the Company and the issuance of letters of credit of up to $500 million under the $1.5 billion credit facility and $200 million under the $750 million credit facility.

At September 30, 2004, total outstanding commercial paper supported by the credit facilities was $348 million and total outstanding letters of credit supported by the credit facilities were $148 million, none of which was issued on behalf of the Company. At September 30, 2004, capacity available under the two credit facilities was $1.75 billion.

Long-Term Debt

In June 2004, the Company repaid $88 million of its 9.25% senior notes.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Shelf Registration

At September 30, 2004, the Company had $1.3 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.

The Company's current financing authorization under the 1935 Act expires at the end of 2004. The Company filed an application with the SEC in August 2004 to renew its 1935 Act financing authorization.

Note 10. Commitments and Contingencies

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, Note 11 to the Consolidated Financial Statements in the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, or Note 13 to the Consolidated Financial Statements in the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, nor have any significant new matters arisen during the quarter ended September 30, 2004.

Guarantees, Letters of Credit and Surety Bonds

As of September 30, 2004, the Company had issued $1.4 billion of guarantees, including: $1.03 billion to support commodity transactions of subsidiaries, $200 million for subsidiary debt and $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 $1.66 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 subsidiari es 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 September 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.

Note 11. Credit Risk

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 September 30, 2004, gross credit exposure related to these transactions totaled $278 million, reflecting the unrealized gains for contracts carried at fair value plus any outstanding receivables (net of payables, where netting agreements exist). Of this amount, investment grade counterparties represent 45% and no single counterparty exceeded 9%. The credit exposure amounts exclude amounts receivable from affiliated companies. As of September 30, 2004 and December 31, 2003, the Company had margin deposit assets of $60 million and $59 million, respectively. The Company had no margin deposit liabilities as of September 30, 2004, or December 31, 2003.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 12. Related Party Transactions

The Company engages in related party transactions primarily with other Dominion subsidiaries. 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. The significant related party transactions are disclosed below.

Transactions with Other Dominion Subsidiaries

The Company transacts with other Dominion subsidiaries for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. The Company also enters into certain financial derivative commodity contracts with Dominion subsidiaries. These contracts, which are principally comprised of commodity swaps and options, are used by the Company to manage commodity price risks associated with the purchases and sales of natural gas. The Company designates the majority of these contracts as cash flow hedges for accounting purposes. The affiliated commodity transactions below include affiliate commodity derivative transactions that resulted in $4 million of gains in the third quarter of 2004 and $3 million in losses in the third quarter of 2003, and $14 million and $22 million in gains in the first nine months of 2004 and 2003, respectively.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2004	2003	2004	2003
	(millions)
Purchases of natural gas from affiliates	$107	$159	$386	$454
Purchases of electric fuel and energy from affiliates	55	31	146	58
Sales of natural gas to affiliates	206	179	770	439
Sales of gas transportation and storage services to affiliates	4	6	15	22
Sales of electricity to affiliates	6	11	28	19

The Company's Consolidated Balance Sheets include derivative assets of $57 million and $50 million with Dominion subsidiaries at September 30, 2004 and December 31, 2003, respectively, and derivative liabilities of $84 million and $48 million with Dominion subsidiaries at September 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.

Dominion Resources Services, Inc., a Dominion subsidiary, provides accounting, legal and certain administrative and technical services to the Company. The Company recognized expense of $44 million and $38 million in the third quarter of 2004 and 2003, respectively, and $127 million and $124 million in the first nine months of 2004 and 2003, respectively, in operations and maintenance expense related to these services.

Transactions with Dominion

As of September 30, 2004 and December 31, 2003, the Company and its subsidiaries have borrowed funds from Dominion under the Dominion money pool ($575 million and $901 million, respectively) and a short-term demand note ($115 million and $126 million, respectively). During the third quarter of 2004 and 2003, the Company incurred $3 million and $4 million, respectively, in interest charges related to these borrowings and $8 million and $10 million, respectively, in the first nine months of 2004 and 2003.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 13. Employee Benefit Plans

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

	Defined Benefit Pension Plans		Other Postretirement Benefit Plans
Three Months Ended September 30,	2004	2003	2004	2003
	(millions)
Service cost	$ 3	$ 2	$ 4	$ 4
Interest cost	8	8	6	6
Expected return on plan assets	(25)	(25)	(3)	(3)
Amortization of prior service cost	1	-	-	-
Amortization of transition obligation	(1)	(1)	1	1
Amortization of net (gain) loss	(1)	(2)	3	3
Net periodic benefit cost (credit)	$(15)	($18)	$11	$11

Company's net periodic benefit cost (credit)⁽¹⁾	($28)	($33)	$16	$16

Nine Months Ended September 30,	2004	2003	2004	2003
Service cost	$ 8	$ 6	$ 13	$ 10
Interest cost	23	23	19	17
Expected return on plan assets	(75)	(73)	(10)	(7)
Amortization of prior service cost	1	-	-	-
Amortization of transition obligation	(2)	(3)	4	3
Amortization of net (gain) loss	(1)	(6)	8	7
Net periodic benefit cost (credit)	$(46)	$(53)	$34	$30

Company's net periodic benefit cost (credit)⁽¹⁾	($84)	($99)	$48	$44

__________

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

Employer Contributions

The Company made no contributions to its defined benefit pension plans or other postretirement benefit plans during the first nine 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 after receiving updated plan information from its actuary. The Company has reviewed updated information received from its actuary and as a result, does not expect to make contributions to its defined benefit pension plans during the remainder of 2004 based on the funded status of each plan and other factors.

PAGE 15

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 14. 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 operating segments:

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

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

Exploration & Production includes 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 deepwater areas of the Gulf of Mexico.

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

	Energy	Delivery	Exploration & Production	Corporate and Other	Eliminations	Consolidated Total
	(millions)
Three Months Ended September 30, 2004
Operating revenue - external customers	$415	$304	$522	$ 7	$ -	$1,248
Operating revenue - intersegment	44	12	28	-	(84)	-
Net income (loss)	38	2	121	(61)	-	100

Three Months Ended September 30, 2003
Operating revenue - external customers	$372	$258	$372	$20	$ -	$1,022
Operating revenue - intersegment	45	10	30	-	(85)	-
Net income	35	1	77	2	-	115

Nine Months Ended September 30, 2004
Operating revenue - external customers	$1,443	$1,825	$1,325	$ 34	$ -	$4,627
Operating revenue - intersegment	154	47	95	-	(296)	-
Net income (loss)	159	130	374	(70)	-	593

Nine Months Ended September 30, 2003
Operating revenue - external customers	$1,169	$1,493	$1,127	$44	$ -	$3,833
Operating revenue - intersegment	164	35	97	-	(296)	-
Net income (loss)	156	104	236	(31)	-	465

PAGE 16

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

The MD&A consists of the following information:

Forward-Looking Statements
Accounting Matters
Results of Operations
Segment Results of Operations
Credit Risk
Future Issues and Other Matters
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 differ materially from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other risks that may cause actual results to differ from predicted results are set forth in Risk Factors and Cautionary Statements That May Affect Future Results.

The Company bases its forward-looking statements on management's beliefs and assumptions using information available at the time the statements are made. The Company cautions the reader not to place undue reliance on its forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially 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

Critical Accounting Policies and Estimates

As of September 30, 2004, there have been no significant changes with regard to critical accounting policies and estimates as disclosed in MD&A in the Company's Annual Report on Form 10-K for the year ended December 31, 2003. The policies disclosed included the accounting for: derivative contracts at fair value; goodwill and long-lived asset impairment testing; employee benefit plans; regulated operations; and gas and oil operations.

PAGE 17

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 September 30,		Nine Months Ended September 30,
	2004	2003	2004	2003
	(millions)
Energy	$ 38	$ 35	$ 159	$ 156
Delivery	2	1	130	104
Exploration & Production	121	77	374	236
Primary operating segments	161	113	663	496

Corporate and Other	(61)	2	(70)	(31)
Consolidated net income	$100	$115	$593	$465

Overview

Third Quarter 2004 vs. 2003

Net income for the third quarter of 2004 decreased 13% to $100 million, as compared to the third quarter of 2003. The Company's primary operating segments contributed an additional $48 million to net income. This increase largely reflects a higher contribution from exploration and production operations primarily due to favorable changes in the fair value of certain oil options that are reported in other operations and maintenance expense. Exploration & Production results were also affected by the recognition of revenue in connection with deliveries under volumetric production payment (VPP) agreements, partially offset by lower gas production, reflecting the sale of mineral rights under the VPP agreements. The results were also positively impacted by higher average realized prices for oil and increased oil production.

The consolidated results for the third quarter of 2004 include a $61 million after-tax loss related to the discontinuance of hedge accounting for certain oil hedges, resulting from a mid-September 2004 interruption of oil production in the Gulf of Mexico caused by Hurricane Ivan, and subsequent changes in the fair value of those hedges. These amounts are reported in the Corporate and Other segment.

Nine Months Ended September 30, 2004 vs. 2003

Net income for the nine months ended September 30, 2004 increased 28% to $593 million, as compared to the first nine months of 2003. The Company's primary operating segments contributed an additional $167 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 favorable changes in the fair value of certain oil options that are reported in other operations and maintenance expenses, increased oil production and lower income taxes as the result of updated estimates for the combined effective state income tax rate. These results were also affected by the recognition of revenue in connection with deliveries under VPP agreements, partially offset by lower gas production, reflecting the sale of mineral rights under the VPP agreements.

PAGE 18

CONSOLIDATED NATURAL GAS COMPANY

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

The consolidated 2004 results include a $61 million after-tax loss related to the discontinuance of hedge accounting for certain oil hedges, resulting from an interruption of oil production in the Gulf of Mexico caused by Hurricane Ivan, and subsequent changes in the fair value of those hedges. Net income was favorably impacted in Corporate and Other by an $8 million gain on the sale of a portion of CNGI's investment in an Australian pipeline business in June 2004 as well as the impact of adjustments to the carrying amount of certain CNGI's investments held for sale.

Analysis of Consolidated Operations

Presented below are selected amounts related to the Company's results of operations.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2004	2003	2004	2003
	(millions)
Operating Revenue
Regulated gas sales	$ 110	$ 120	$ 953	$ 851
Nonregulated electric sales ⁽¹⁾	115	72	303	170
Nonregulated gas sales ⁽¹⁾	352	310	1,426	1,103
Gas transportation and storage ⁽¹⁾	155	145	593	559
Gas and oil production	350	295	963	890
Other ⁽¹⁾	166	80	389	260

Operating Expenses
Purchased gas, net ⁽¹⁾	387	353	1,951	1,547
Electric fuel and energy purchases⁽¹⁾	101	60	269	142
Liquids, pipeline capacity and other purchases	98	41	207	137
Other operations and maintenance ⁽¹⁾	262	168	535	546
Depreciation, depletion and amortization	156	152	464	442
Other taxes	55	45	191	175

Other income	3	10	43	2
Interest and related charges ⁽¹⁾	42	36	125	115
Income tax expense	50	62	335	261

(1) Includes transactions with other Dominion subsidiaries related to Dominion's enterprise-wide price risk management and other activities.
See Note 12 to the Consolidated Financial Statements for a description of transactions with affiliates.

An analysis of the Company's results of operations for the three and nine months ended September 30, 2004, as compared to the same periods of 2003 follows.

PAGE 19

CONSOLIDATED NATURAL GAS COMPANY

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

Third Quarter 2004 vs. 2003

Operating Revenue

Regulated gas sales revenue decreased 8% to $110 million, largely resulting from a $14 million decrease associated with milder weather, lower industrial sales and customer migration to Energy Choice programs, partially offset by a $4 million increase due to higher rates primarily related to the recovery of higher gas prices. The effect of this net decrease in regulated gas sales revenue was largely offset by a comparable decrease in Purchased gas expense.

Nonregulated electric sales revenue increased 60% to $115 million resulting primarily from customer growth in nonregulated retail energy sales, partially offset by decreased revenue from the Company's power generation facility and the sale of CNGI's Kauai, Hawaii generation facility in December 2003.

Nonregulated gas sales revenue increased 14% to $352 million primarily reflecting:

A $14 million increase in revenue from producer services operations, driven by higher prices ($37 million), partially offset by lower volumes ($23 million). This increase in nonregulated gas sales revenue was largely offset by a corresponding increase in Purchased gas, net expense; and

A $27 million increase in revenue from sales of purchased gas by exploration and production operations, entered into to facilitate gas transportation and other agreements. This increase in nonregulated gas sales revenue was largely offset by a corresponding increase in Purchased gas, net expense.

Gas transportation and storage revenue increased 7% to $155 million, largely due to the August 2003 reactivation of the Cove Point LNG facility, which was acquired by the Company in September 2002.

Gas and oil production revenue increased 19% to $350 million primarily reflecting:

A $61 million increase in revenue recognized related to deliveries under VPP transactions;

A $17 million increase in revenue from oil production, largely reflecting higher volumes; partially offset by

A $28 million decrease in revenue from gas production, primarily reflecting the sale of mineral rights under the VPP agreements.

Other revenue increased 108% to $166 million, primarily reflecting:

A $25 million increase in sales of extracted products, reflecting primarily higher volumes; and

A $61 million increase in sales of purchased oil by exploration and production operations, reflecting both higher volumes and higher prices. The increase in other revenue was largely offset by a corresponding increase in Liquids, pipeline capacity and other purchases expense.

Operating Expenses and Other Items

Purchased gas, net expense increased 10% to $387 million, primarily reflecting:

A $26 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;

A $15 million increase associated with producer services operations, driven by higher prices ($39 million) offset by lower volumes ($24 million), as discussed above in Nonregulated gas sales revenue; partially offset by

A $7 million decrease associated with regulated gas sales discussed above in Regulated gas sales revenue.

Electric fuel and energy purchases expense increased 68% to $101 million, primarily reflecting new business at the Company's nonregulated retail energy marketing operations, partially offset by lower expenses related to the Company's power generation facility and sale of CNGI's Kauai, Hawaii generation facility in December 2003.

Liquids, pipeline capacity and other purchases expense increased 139% to $98 million, primarily reflecting an increase in the volume and the cost of oil purchased for resale as discussed above in Other revenue.

PAGE 20

CONSOLIDATED NATURAL GAS COMPANY

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

Other operations and maintenance expense increased 56% to $262 million, primarily reflecting the following:

A $5 million increase in costs due to lower pension credits;

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

A $15 million increase in costs related to oil and gas production activities; offset by

A $31 million net benefit primarily due to favorable changes in the fair value of certain oil options held by the Exploration & Production segment. As provided for in SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, the Company excludes changes in options' time value from 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 and maintenance expenses. During 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 $78 million in mark-to-market gains attributable to favorable changes in time value.

Other taxes expense increased 22% to $55 million, primarily reflecting higher severance taxes, higher property taxes resulting from property additions, and higher gross receipts tax primarily resulting from increased nonregulated retail sales activity.

Nine Months Ended September 30, 2004 vs. 2003

Operating Revenue

Regulated gas sales revenue increased 12% to $953 million, largely resulting from a $152 million increase due to higher rates for regulated gas distribution operations primarily related to the recovery of higher gas prices, partially offset by a $69 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 78% to $303 million, resulting primarily from increased volumes ($116 million), reflecting customer growth, and higher prices ($32 million) in the Company's nonregulated retail energy marketing operations, partially offset by lower revenue ($15 million) due to the sale of CNGI's generation assets in Kauai, Hawaii in December 2003.

Nonregulated gas sales revenue increased 29% to $1.4 billion primarily reflecting:

A $177 million increase in revenue from producer services operations, driven by higher volumes, largely offset by a corresponding increase in Purchased gas, net expense;

A $112 million increase in revenue from nonregulated retail energy marketing operations, reflecting higher prices ($42 million) and higher volumes ($70 million);

A $31 million increase in revenue from sales of purchased gas by exploration and production operations, entered into to facilitate gas transportation and other agreements. This increase in nonregulated gas sales revenue was largely offset by a corresponding increase in Purchased gas, net expense.

Gas transportation and storage revenue increased 6% to $593 million, largely due to the August 2003 reactivation of the Cove Point LNG facility, which was acquired by the Company in September 2002.

Gas and oil production revenue increased 8% to $963 million primarily reflecting:

A $141 million increase in revenue recognized related to deliveries under VPP transactions;

A $16 million increase in revenue from oil production, reflecting higher volumes; partially offset by

An $88 million decrease in revenue from gas production, primarily reflecting the sale of mineral rights under the VPP agreements.

PAGE 21

CONSOLIDATED NATURAL GAS COMPANY

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

Other revenue increased 50% to $389 million, primarily reflecting:

A $42 million increase in sales of extracted products, primarily reflecting higher volumes; and

A $76 million increase in sales of purchased oil by exploration and production operations, reflecting both higher volumes and higher prices. The increase in other revenue was largely offset by a corresponding increase in Liquids, pipeline capacity and other purchases expense.

Operating Expenses and Other Items

Purchased gas, net expense increased 26% to $2.0 billion, primarily reflecting:

A $170 million increase associated with producer services operations, largely reflecting higher volumes, as discussed above in Nonregulated gas sales revenue;

A $77 million increase associated with nonregulated retail energy marketing, primarily reflecting higher volumes; and

An $82 million increase associated with regulated gas sales discussed above in Regulated gas sales revenue;

A $42 million increase related to gas transmission operations; and

A $22 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.

Electric fuel and energy purchases expense increased 89% to $269 million, primarily reflecting the following:

A $132 increase related to nonregulated retail energy marketing operations reflecting increased volumes ($113 million) and higher prices ($19 million); and

A $5 million increase related to the Company's power generation facility, partially offset by

A $10 million decrease related to the sale of CNGI's Kauai, Hawaii generation facility in December 2003.

Liquids, pipeline capacity and other purchases expense increased 51% to $207 million, primarily reflecting an increase in the volume and the cost of oil purchased for resale as discussed above in Other revenue.

Other operations and maintenance expense decreased 2% to $535 million, primarily reflecting the following:

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

A $6 million increase in costs related to oil and gas production activities;

A $19 million increase in operating costs for gas transmission operations, including the reactivation of the Cove Point LNG facility; and

A $20 million increase resulting from lower pension credits and higher other postretirement benefit (OPEB) costs; offset by

A $114 million net benefit primarily due to favorable changes in the fair value of certain oil options. During 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 $120 million in mark-to-market gains attributable to favorable changes in time value;

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 $10 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.

Depreciation, depletion and amortization expense increased 5% to $464 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 taxes expense increased 9% to $191 million, primarily reflecting higher property taxes resulting from property additions, higher gross receipts tax primarily resulting from increased nonregulated retail sales activity, and higher severance taxes.

PAGE 22

CONSOLIDATED NATURAL GAS COMPANY

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

Other income increased $41 million, primarily reflecting a $26 million benefit in 2004 related to a portion of CNGI's equity investment in an Australian pipeline business, consisting of an $18 million favorable adjustment to the carrying amount of this investment and an $8 million gain on its sale. In 2003, an $18 million impairment charge was recognized on this investment, based on estimated fair value at that time.

Interest expense increased 9% to $125 million, primarily reflecting:

An $8 million decrease in capitalization of interest in 2004 related to oil and gas operations; and

A $3 million increase due to the consolidation of debt related to a special purpose lessor entity as a result of the adoption of FIN 46R on December 31, 2003.

Income tax expense increased 28% to $335 million primarily as a result of an increase in pre-tax income and an increase in the valuation allowance related to CNGI investments, partially offset by a reduction in state income taxes.

Segment Results of Operations

Energy Segment

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2004	2003	2004	2003
	(millions)
Net income contribution	$38	$35	$159	$156
Gas sales (bcf)	50	55	178	152
Gas transmission throughput (bcf)	112	84	535	445

__________________
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 September 30,	Nine Months Ended September 30,
	2004 vs. 2003	2004 vs. 2003
	Increase	Increase
	(Decrease)	(Decrease)
	(millions)
Gas prices	$(2)	$ 2
Cove Point LNG operations	2	8
Other	_3	(7)
Change in net income contribution	$ 3	$ 3

The Energy segment's net income increased $3 million for the three and nine months ended September 30, 2004, respectively, as compared to the same periods of 2003, primarily reflecting the following:

Lower gas prices in the third quarter and higher gas prices in the first nine months on producer services operations;

A higher contribution from the Cove Point LNG facility due to its reactivation in August 2003; and

Higher operations and maintenance expenses, including lower net pension credits, increased OPEB costs and higher contractor services expense. In the third quarter, these higher expenses were more than offset by higher gas transmission margins due primarily to higher sales of extracted products.

PAGE 23

CONSOLIDATED NATURAL GAS COMPANY

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

Delivery Segment

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2004	2003	2004	2003
	(millions)
Net income contribution	$2	$1	$130	$104
Throughput:
Gas sales-regulated (bcf)	9	10	87	95
Gas transportation-regulated (bcf)	34	31	178	171
Total throughput - regulated (bcf)	43	41	265	266

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

	Three Months Ended September 30,	Nine Months Ended September 30,
	2004 vs. 2003	2004 vs. 2003
	Increase	Increase
	(Decrease)	(Decrease)
	(millions)

Weather	$ -	$(8)
Nonregulated retail energy marketing operations	8	24
Other margins	(4)	4
Pension and OPEB expense	(2)	(9)
Bad debt expense	1	12
Other	(2)	3
Change in net income contribution	$1	$26

The Delivery segment's net income increased $1 million and $26 million for the three and nine months ended September 30, 2004, respectively, as compared to the same periods of 2003, primarily reflecting the following:

Lower regulated gas sales attributable to comparably warmer weather;

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

Lower contributions from regulated gas operations for the quarter due to increased gas costs, lower other revenue, and lower customer usage exclusive of weather, partially offset by increased industrial transport; higher contributions from regulated gas operations year-to-date, reflecting an increase in production and gathering revenue, higher industrial sales and transport revenue and lower purchased gas prices in the second quarter of 2004;

Lower net pension credits and an increase in OPEB costs; and

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

PAGE 24

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.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2004	2003	2004	2003
	(millions)
Net income contribution	$121	$77	$374	$236

Gas production (bcf)	64.7	70.1	201.3	210.4
Oil production (million bbls)	2.5	1.9	6.5	5.9

Average realized prices with hedging results:
Gas (per mcf)⁽¹⁾	$4.12	$4.10	$4.09	$4.20
Oil (per bbl)	$26.23	$24.54	$25.35	$25.13

Average realized prices without hedging results:
Gas (per mcf)⁽¹⁾	$5.67	$4.90	$5.60	$5.45
Oil (per bbl)	$42.65	$29.95	$38.46	$30.70

Other information:
DD&A (unit of production rate per mcfe)	$1.39	$1.38	$1.37	$1.32

_____________________
bbl = barrel
mcf = thousand cubic feet
mcfe = thousand cubic feet equivalent

^{(1) Excludes $74 million and $14 million of revenue recognized in the third quarter of 2004 and 2003, respectively, and $154 and $14 million of revenue recognized in the year-to-date period of 2004 and 2003, respectively, under the VPP agreements described in Note 8 to the Consolidated Financial Statements in the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 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.}

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

	Three Months Ended September 30,	Nine Months Ended September 30,
	2004 vs. 2003	2004 vs. 2003
	Increase	Increase
	(Decrease)	(Decrease)
	(millions)
VPP revenue	$ 38	$ 88
Gas and oil-production	(5)	(21)
Gas and oil-prices	5	(6)
Operations and maintenance expense	6	63
DD&A-production	1	4
DD&A-rate	(1)	(9)
Income taxes	2	22
Other	(2)	(3)
Change in net income contribution	$ 44	$ 138

PAGE 25

CONSOLIDATED NATURAL GAS COMPANY

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

The Exploration & Production segment's net income increased $44 million and $138 million for the three and nine months ended September 30, 2004, respectively, as compared to the same periods of 2003, primarily reflecting the following:

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

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

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

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

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

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 the volume of business transactions.

Corporate and Other

Corporate and Other also includes CNGI and other minor subsidiaries.

Presented below are the Corporate and Other segment's after-tax results for the three and nine months ended September 30, 2004 and 2003:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2004	2003	2004	2003
	(millions)
Net income (loss)	$ (61)	$ 2	$ (70)	$ (31)

Three Months Ended September 30, 2004 vs. 2003

Corporate and Other experienced a net loss of $61 million for 2004, compared to a net income of $2 million in 2003. The 2004 results primarily reflect $96 million of incremental operations and maintenance expense ($61 million after-tax) related to the discontinuance of hedge accounting for certain oil hedges, resulting from an interruption of oil production in the Gulf of Mexico caused by Hurricane Ivan, and subsequent changes in the fair value of those hedges, attributable to the Exploration & Production segment.

Nine Months Ended September 30, 2004 vs. 2003

Corporate and Other experienced a net loss of $70 million for 2004, compared to a net loss of $31 million in 2003. The net loss recognized for 2004 primarily reflected the following:

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

An additional $33 million tax valuation allowance recorded in the second quarter of 2004 related to certain CNGI investments that were held for sale; partially offset by

A $26 million benefit in 2004 related to a portion of CNGI's equity investment in an Australian pipeline business, consisting of an $18 million favorable adjustment to the carrying amount of this investment and an $8 million gain on its sale.

PAGE 26

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 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:

A $5 million after-tax loss associated with the cumulative effect of a change in accounting principle related to the adoption of SFAS No. 143 on January 1, 2003 attributable to the Energy segment; and

A $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 September 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. At September 30, 2004, the Company held no collateral made available by its counterparties.

	Gross Credit Exposure
	(millions)
Investment grade⁽¹⁾	$107
Non-investment grade⁽²⁾	54
No external ratings:
Internally rated-investment grade⁽³⁾	17
Internally rated-non-investment grade⁽⁴⁾	100
Total	$278

_______________

(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 19% of the total gross credit exposure.
(2) The five largest counterparty exposures, combined, for this category represented approximately 17% of the total gross credit exposure.
(3) The five largest counterparty exposures, combined, for this category represented approximately 4% of the total gross credit exposure.
(4) The five largest counterparty exposures, combined, for this category represented approximately 7% of the total gross credit exposure.

Future Issues and Other Matters

American Jobs Creation Act of 2004

The American Jobs Creation Act of 2004 (the Act) was signed into law in October 2004 and has several provisions for energy companies including a deduction related to qualified production activities taxable income. Under the Act, qualified production activities include the Company's electric generation and oil and gas extraction activities.

The FASB is currently reviewing the impact of the qualified production activities deduction on deferred taxes and is expected to issue guidance in the fourth quarter of 2004. Until this guidance is issued, the impact on the Company cannot be determined.

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CONSOLIDATED NATURAL GAS COMPANY

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

Risk Factors and Cautionary Statements That May Affect Future Results

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

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

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

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

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

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

For additional information concerning derivatives and commodity-based trading contracts, see "Quantitative and Qualitative Disclosures About Market Risk-Market Rate Sensitive Instruments and Risk Management" and Notes 2 and 9 to the Consolidated Financial Statements in its Annual Report on Form 10-K for the year ended December 31, 2003.

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CONSOLIDATED NATURAL GAS COMPANY

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

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

Short-term market declines in the prices of natural gas and oil could adversely affect the Company's financial results by causing a permanent write-down of its natural gas and oil properties as required by the full cost method of accounting. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. If net capitalized costs exceed the present value of estimated future net revenues based on hedge-adjusted period-end prices from the production of proved gas and oil reserves (the ceiling test) 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 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 September 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 change its business plans in ways that may adversely affect the Company's growth and earnings. A reduction in the Company's credit ratings by either Standard & Poor's or Moody's could increase its borrowing costs and adversely affect operating results and could require it to post additional margin in connection with some of its trading and marketing activities.

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, the energy industry or its operations specifically. New accounting standards could be issued that could change the way the Company records revenues, expenses, assets and liabilities. These changes in accounting standards could adversely affect the Company's reported earnings or could increase reported liabilities.

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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 September 30, 2004 reflects $218 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.

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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.

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

ITEM 6. EXHIBITS

(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	Consolidated Natural Gas Company agrees to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of its total consolidated assets.
	10	$1,500,000,0000 Three-Year Credit Agreement among Consolidated Natural Gas Company and Barclays Bank, as Administrative Agent for the Lenders, dated August 10, 2004 (filed herewith).
	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).

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 3, 2004	/s/ Steven A. Rogers Steven A. Rogers Vice President and Controller (Principal Accounting Officer)