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 June 30, 2004

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

Commission File Number 1-3196

CONSOLIDATED NATURAL GAS COMPANY
(Exact name of registrant as specified in its charter)

DELAWARE (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 June 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 Six Months Ended June 30, 2004 and 2003	3
	Consolidated Balance Sheets - June 30, 2004 and December 31, 2003	4
	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2004 and 2003	6
	Notes to Consolidated Financial Statements	7
Item 2	Management's Discussion and Analysis of Results of Operations	17
Item 4	Controls and Procedures	30
	PART II. Other Information
Item 1	Legal Proceedings	31
Item 5	Other Items	31
Item 6	Exhibits and Reports on Form 8-K	31

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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 June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
	(millions)

Operating Revenue
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
External suppliers	371	235	1,285	899
Affiliated suppliers	129	170	279	295
Electric fuel and energy purchases
External suppliers	35	20	77	55
Affiliated suppliers	53	17	91	27
Liquids, pipeline capacity and other purchases	58	43	109	96
Other operations and maintenance
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-junior subordinated notes payable to affiliated trust	4	-	8	-
Interest expense - other	37	36	75	71
Distributions-mandatorily redeemable trust preferred securities	-	4	-	8
Total interest and related charges	41	40	83	79

Income before income taxes	296	163	778	554
Income tax expense	114	60	285	199
Income before cumulative effect of a change in accounting principle	182	103	493	355
Cumulative effect of a change in accounting principle (net of income taxes of $3)	-	-	-	(5)

Net income	$ 182	$ 103	$ 493	$ 350

____________

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

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CONSOLIDATED NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)

	June 30, 2004	December 31, 2003⁽¹⁾
	(millions)
ASSETS

Current Assets
Cash and cash equivalents	$ 29	$ 39
Customer accounts receivable (net of allowance of $30 in 2004 and $37 in 2003)	691	795
Other accounts receivable	51	45
Receivables due from affiliates	412	340
Inventories	150	238
Prepayments	35	56
Derivative assets	186	106
Other	272	296
Total current assets	1,826	1,915

Investments
Investment in affiliates	212	203
Other	83	79
Total investments	295	282

Property, Plant and Equipment
Property, plant and equipment	16,458	15,854
Accumulated depreciation, depletion and amortization	(5,932)	(5,674)
Net property, plant and equipment	10,526	10,180

Deferred Charges and Other Assets
Goodwill, net	623	626
Regulatory assets	341	328
Prepaid pension cost	928	872
Derivative assets	300	84
Other	210	210
Total deferred charges and other assets	2,402	2,120

Total assets	$15,049	$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)}

	June 30, 2004	December 31, 2003⁽¹⁾
	(millions)
LIABILITIES AND SHAREHOLDER'S EQUITY

Current Liabilities
Securities due within one year	$ 555		$ 501
Short-term debt	-		151
Accounts payable, trade	630		655
Payables to affiliates	122		118
Affiliated current borrowings	645		1,027
Accrued interest, payroll and taxes	241		214
Derivative liabilities	991		620
Other	468		278
Total current liabilities	3,652		3,564

Long-Term Debt
Long-term debt	3,052		3,213
Junior subordinated notes payable to affiliated trust	206		206
Total long-term debt	3,258		3,419


Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits	1,858		1,760
Asset retirement obligations	245		240
Derivative liabilities	1,057		669
Regulatory liabilities	216		212
Other	458		268
Total deferred credits and other liabilities	3,834		3,149
Total liabilities	10,744		10,132

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	2,478		2,478
Retained earnings	830		608
Accumulated other comprehensive loss	(819)		(537)
Total common shareholder's equity	4,305		4,365

Total liabilities and shareholder's equity	$15,049		$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)}

	Six Months Ended June 30,
	2004	2003
	(millions)

Operating Activities
Net income	$ 493	$ 350
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	308	290
Deferred income taxes and investment tax credits, net	214	117
Valuation adjustment on CNG International assets	(18)	-
Cumulative effect of a change in accounting principle, net of income taxes	-	5
Changes in:
Accounts receivable	98	56
Affiliated receivables and payables	(68)	(134)
Inventories	88	(5)
Prepayments	21	51
Margin deposit assets and liabilities	14	(121)
Deferred purchased gas costs, net	1	(129)
Accounts payable, trade	(25)	(20)
Accrued interest, payroll and taxes	27	17
Other operating assets and liabilities	(62)	142
Net cash provided by operating activities	1,091	619

Investing Activities
Additions to gas and oil properties, including acquisitions	(543)	(475)
Proceeds from sales of gas and oil properties	413	-
Plant construction and other property additions	(132)	(197)
Other	47	(1)
Net cash used in investing activities	(215)	(673)

Financing Activities
Repayment of short-term debt, net	(151)	(380)
Issuance (repayment) of affiliated current borrowings, net	(382)	702
Repayment of long-term debt	(88)	-
Common stock dividend payments	(271)	(245)
Other	6	-
Net cash (used in) provided by financing activities	(886)	77

Increase (decrease) in cash and cash equivalents	(10)	23
Cash and cash equivalents at beginning of period	39	22
Cash and cash equivalents at end of period	$ 29	$ 45

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 1.4 million residential and commercial 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 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 Report on Form 10-Q for the quarter ended March 31, 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 June 30, 2004, its results of operations for the three and six months ended June 30, 2004 and 2003, and its cash flows for the six months ended June 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 where the Company is 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

FIN 46R

The Company adopted Financial Accounting Standards Board (FASB) Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, (FIN 46R) for its interests in variable interest entities (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 Statement of Financial Accounting Standards (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. 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.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 6. Operating Revenue

The Company's operating revenue consists of the following:

	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
External customers	148	171	511	533
Affiliated customers	271	161	564	260
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

Note 7. Comprehensive Income

The following table presents total comprehensive income:

	Three Months Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
	(millions)

Net income	$182	$103	$493	$350
Other comprehensive income (loss):
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.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 8. Volumetric Production Payment (VPP) Transaction

In May 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 natural gas reserves 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 perio d August 2003 through August 2007.

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

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

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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.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 12. Significant Financing Transactions

Credit Facilities

In June 2004, the Company entered into a $300 million letter of credit agreement that terminates in August 2004 and a $100 million letter of credit agreement that terminates in June 2007. 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 June 30, 2004, outstanding letters of credit under these agreements totaled $300 million.

In August 2003, the Company entered into a $1.0 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

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 June 30, 2004, total outstanding commercial paper supported by the credit facilities was $610 million. At 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.

Long-Term Debt

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

Shelf Registration

At June 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 intends to file an application with the SEC in August 2004 to renew its 1935 Act financing authorization.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 13. 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, 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

As of June 30, 2004, the Company had issued $1.4 billion of guarantees, including: $1.0 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 $1.3 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 t he 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.

Note 14. 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 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 receiv ables (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.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 15. 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 total net realized gains on affiliate commodity derivative transactions of $7 million and $20 million in the second quarter of 2004 and 2003, respectively, and $10 million and $25 million in the first six months of 2004 and 2003, respectively.

	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

The Company's 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.

Dominion Resources Services, Inc., a Dominion subsidiary, provides accounting, legal and certain administrative and technical services to the Company. The Company recognized expense of $39 million in both the second quarter of 2004 and 2003, and $83 million and $86 million in the first six months of 2004 and 2003, respectively, in operations and maintenance expense related to these services.

Transactions with Dominion

As of 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). During the second quarter of 2004 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.

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CONSOLIDATED NATURAL GAS COMPANY

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.

Employer Contributions

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.

PAGE 16

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 17. 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 liquefied natural gas 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 CNGI and other minor subsidiaries. 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 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

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
Risk Factors and Cautionary Statements That May Affect Future Results

Forward-Looking Statements

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

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

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

Accounting Matters

Critical Accounting Policies and Estimates

As of June 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 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)

Analysis of Consolidated Operations

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

	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)

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

Three Months Ended June 30, 2004 vs. 2003

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)

Nonregulated gas sales revenue increased 26% to $419 million primarily reflecting:

A $65 million increase in revenue from producer services operations, driven by higher prices ($19 million) and higher volumes ($46 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;

A $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

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

Gas transportation 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.

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)

Other operations and maintenance expense decreased 37% to $121 million, primarily reflecting the following:

A $49 million benefit primarily due to favorable changes in the fair value of certain oil options. 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 $42 million in mark-to-market gains. Future gains and losses on options will depend upon the relationship between an option's cost and future commodity prices;

A $22 million asset impairment charge recognized 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

A $5 million decrease in bad debt expense.

These decreases were partially offset by lower net pension credits and higher other postretirement benefit (OPEB) costs ($8 million).

Other income 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.

Income 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.

Six Months Ended June 30, 2004 vs. 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)

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

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

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

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

A $15 million increase in sales of purchased oil by exploration and production operations, reflecting higher prices;

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

A $6 million increase in distribution operations' gathering service revenue, reflecting higher volumes.

Operating Expenses and Other Items

Purchased gas, net expense increased 31% to $1.6 billion, primarily reflecting:

An $86 million increase associated with nonregulated retail energy marketing, primarily reflecting higher volumes;

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)

Segment Results of Operations

Energy Segment

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

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 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

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

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:

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;

Higher contributions from regulated gas operations, reflecting an increase in production and gathering revenue, higher industrial sales and transport revenue and lower purchased gas prices;

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 six month period also reflects increased reserves required in the first quarter of 2003 due to colder than normal weather.

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.

	Three Months Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
	(millions)
Net income contribution	$144	$75	$253	$159

Gas production (bcf)	67.0	70.9	136.6	140.4
Oil production (million bbls)	2.1	2.0	4.0	4.0

Average realized prices with hedging results:
Gas (per mcf)⁽¹⁾	$4.05	$4.22	$4.07	$4.25
Oil (per bbl)	$25.24	$24.70	$24.78	$25.41

Average realized prices without hedging results:
Gas (per mcf)⁽¹⁾	$5.67	$5.27	$5.57	$5.72
Oil (per bbl)	$37.40	$28.41	$35.78	$31.07

Other information:
DD&A (unit of production rate per mcfe)	$1.37	$1.34	$1.36	$1.30

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

⁽¹⁾ 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.

Presented below, on an after-tax basis, are the key factors impacting the Exploration & Production 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)

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

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:

Recognition of revenue in connection with deliveries under VPP agreements;

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

Higher oil production reflecting the beginning of 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. Future gains and losses on options will depend upon the relationship between an option's cost and future commodity prices;

A 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

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 operating results for the three and six months ended June 30, 2004 and 2003:

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

Three Months Ended June 30, 2004 vs. 2003

Corporate and Other experienced a net loss of $28 million for 2004, compared to a net loss of $23 million in 2003. The 2004 results primarily reflect an increase in an income tax valuation allowance related to CNGI investments, partially offset by an $8 million gain on the sale of a portion of CNGI's investment in an Australian pipeline business in June 2004. The 2003 net loss 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.

Six Months Ended June 30, 2004 vs. 2003

Corporate and Other experienced a net loss of $8 million for 2004, compared to a net loss of $33 million in 2003. The 2004 results reflect an additional tax valuation allowance recorded in the second quarter of 2004 related to certain CNGI investments classified as held for sale, partially offset by an $8 million gain on the sale of a portion of CNGI's investment in an Australian pipeline business and an $18 million benefit from adjusting the carrying amount of this investment in the first quarter to its then current estimate of fair value.

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:

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 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.

	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

_______________

(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.

PAGE 28

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 and ratings; changes in accounting standards; collective bargaining agreements and labor negotiations; the risks of operating businesses in regulated industries that are becoming deregulated; 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 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.

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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 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 acquis ition, 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.

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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 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.

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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.

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).
	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).

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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.

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

August 4, 2004	/s/ Steven A. Rogers
	Steven A. Rogers Vice President and Controller (Principal Accounting Officer)