Consolidated Natural Gas 10-Q 2005 Q2 Quarterly report

UNITED STATES

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, 2005

or

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

Commission File Number 1-3196

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

DELAWARE (State or other jurisdiction of incorporation or organization)	54-1966737 (I.R.S. Employer Identification No.)
120 Tredegar Street RICHMOND, VIRGINIA (Address of principal executive offices)	23219 (Zip Code)
(804) 819-2000 (Registrant's telephone number)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes   X  No        

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, 2005, the latest practicable date for determination, 100 shares of common stock, without par value, of the registrant were outstanding.

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

PAGE 2

CONSOLIDATED NATURAL GAS COMPANY

INDEX

		Page   Number
PART I. Financial Information
Item 1.	Consolidated Financial Statements
	Consolidated Statements of Income - Three and Six Months Ended June 30, 2005 and 2004	3
	Consolidated Balance Sheets - June 30, 2005 and December 31, 2004	4
	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2005 and 2004	6
	Notes to Consolidated Financial Statements	7
Item 2.	Management's Discussion and Analysis of Results of Operations	21
Item 4.	Controls and Procedures	36
	PART II. Other Information
Item 1.	Legal Proceedings	37
Item 6.	Exhibits	37

PAGE 3

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,
	2005	2004	2005	2004
	(millions)
Operating Revenue
External customers	$1,353	$1,011	$3,465	$2,781
Affiliated customers	216	290	477	598
Total operating revenue	1,569	1,301	3,942	3,379
Operating Expenses
Purchased gas, net
External suppliers	385	371	1,427	1,285
Affiliated suppliers	163	129	296	279
Electric fuel and energy purchases
External suppliers	24	35	51	77
Affiliated suppliers	43	53	88	91
Liquids, pipeline capacity and other purchases	86	58	188	109
Other operations and maintenance
External	159	83	383	193
Affiliated	44	38	87	80
Depreciation, depletion and amortization	169	154	335	308
Other taxes	60	54	150	136
Total operating expenses	1,133	975	3,005	2,558
Income from operations	436	326	937	821
Other income	9	11	12	40
Interest and related charges:
Interest expense	49	37	97	75
Interest expense - junior subordinated notes payable to           affiliated trust	4	4	8	8
Total interest and related charges	53	41	105	83
Income before income taxes	392	296	844	778
Income tax expense	141	114	306	285
Net income	$   251	$   182	$ 538	$ 493

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

PAGE 4

CONSOLIDATED NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)

	June 30, 2005	December 31,  2004(1)
	(millions)
ASSETS
Current Assets
Cash and cash equivalents	$      13	$      19
Customer accounts receivable (net of allowance of $33 in 2005 and $28 in 2004)	864	1,044
Other accounts receivable	212	61
Receivables due from affiliates	99	125
Inventories	179	222
Derivative assets	1,210	504
Deferred income taxes	499	280
Other	555	374
Total current assets	3,631	2,629
Investments	306	291
Property, Plant and Equipment, Net
Property, plant and equipment	18,197	17,220
Accumulated depreciation, depletion and amortization	(6,464)	(6,170)
Total property, plant and equipment, net	11,733	11,050
Deferred Charges and Other Assets
Goodwill, net	623	623
Regulatory assets	359	369
Prepaid pension cost	1,035	984
Derivative assets	867	541
Other	259	235
Total deferred charges and other assets	3,143	2,752
Total assets	$18,813	$16,722

________________
⁽¹⁾The Consolidated Balance Sheet at December 31, 2004 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, 2005	December 31,  2004(1)
	(millions)
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities
Securities due within one year	$     -		$     150
Accounts payable, trade	805		949
Payables to affiliates	127		111
Affiliated current borrowings	1,894		1,195
Accrued interest, payroll and taxes	201		229
Derivative liabilities	2,405		1,237
Other	409		341
Total current liabilities	5,841		4,212
Long-Term Debt
Long-term debt	3,450		3,454
Junior subordinated notes payable to affiliated trust	206		206
Total long-term debt	3,656		3,660
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits	2,326		2,321
Asset retirement obligations	246		251
Derivative liabilities	2,158		1,234
Regulatory liabilities	231		223
Other	333		341
Total deferred credits and other liabilities	5,294		4,370
Total liabilities	14,791		12,242
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	2,522		2,520
Retained earnings	1,208		993
Accumulated other comprehensive loss	(1,524)		(849)
Total common shareholder's equity	4,022		4,480
Total liabilities and shareholder's equity	$18,813		$16,722

________________
⁽¹⁾The Consolidated Balance Sheet at December 31, 2004 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,
	2005	2004
	(millions)
Operating Activities
Net income	$  538	$  493
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization	335	308
Deferred income taxes and investment tax credits, net	186	214
Net unrealized (gain) loss on energy-related derivatives	58	(76)
Valuation adjustment on CNG International assets	-	(18)
Changes in:
Accounts receivable	29	98
Affiliated receivables and payables	42	(68)
Inventories	43	88
Margin deposit assets and liabilities	(240)	14
Accounts payable, trade	(184)	(25)
Accrued interest, payroll and taxes	(28)	27
Deferred revenue	(125)	(80)
Other operating assets and liabilities	(52)	116
Net cash provided by operating activities	602	1,091
Investing Activities
Additions to gas and oil properties, including acquisitions	(753)	(543)
Proceeds from sales of gas and oil properties	86	413
Plant construction and other property additions	(154)	(132)
Other	(12)	47
Net cash used in investing activities	(833)	(215)
Financing Activities
Repayment of short-term debt, net	-	(151)
Issuance (repayment) of affiliated current borrowings, net	699	(382)
Repayment of long-term debt	(150)	(88)
Common stock dividend payments	(324)	(271)
Other	-	6
Net cash provided by (used in) financing activities	225	(886)
Decrease in cash and cash equivalents	(6)	(10)
Cash and cash equivalents at beginning of period	19	39
Cash and cash equivalents at end of period	$   13	$   29

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

PAGE 7

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.  Nature of Operations
Consolidated Natural Gas Company (the Company), a public utility holding company registered under the Public Utility Holding Company Act of 1935 (1935 Act), is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion). The Company, 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 1.1 million residential and commercial gas and electric customer accounts in the Northeast, Mid-Atlantic and Midwest. The Company operates an interstate gas transmission pipeline and underground natural gas storage system in the Northeast, Midwest, and the Mid-Atlantic states and a liquefied natural gas (LNG) import and storage facility in Maryl and. The Company's producer services operation involves 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: Delivery, Energy 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, 2004 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2005.

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, 2005, its results of operations for the three and six months ended June 30, 2005 and 2004, and its cash flows for the six months ended June 30, 2005 and 2004.

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, 2004 for a more detailed discussion of the Company's estimation techniques.

PAGE 8

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATEDFINANCIAL 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 2004 Consolidated Financial Statements have been reclassified to conform to the 2005 presentation. These reclassifications had no effect on net income.

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

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

	Three Months Ended June 30,		Six Months Ended June 30,
	2005	2004	2005	2004
	(millions)
Sale activity included in operating revenue	$83	$61	$176	$107
Purchase activity included in operating expenses(1)	79	55	168	97

_________________________
⁽¹⁾Included in Liquids, pipeline capacity and other purchases

Note 3.     Recently Issued Accounting Standards
FIN 47
In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47,Accounting for Conditional Asset Retirement Obligations (FIN 47), which clarifies that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when the obligation is incurred - generally upon acquisition, construction, or development and (or) through the normal operation of the asset, if the fair value of the liability can be reasonably estimated. A conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Uncertainty about the timing and (or) method of settlement is required to be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair va lue of an asset retirement obligation. FIN 47 is effective for fiscal years ending after December 15, 2005. The Company is currently evaluating the impact that FIN 47 may have on its results of operations and financial condition.

PAGE 9

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

SFAS No. 154
In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections-a replacement of APB Opinion No. 20 and FASB Statement No. 3. SFAS No. 154 applies to all voluntary changes in accounting principle and requires retrospective application to prior periods' financial statements of a voluntary change in accounting principle unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. The Company will apply the provisions of SFAS No. 154 beginning January 1, 2006.

EITF 04-5
In June 2005, the FASB ratified the consensus reached by the EITF on Issue No. 04-5, Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights. EITF 04-5 provides guidance in assessing when a general partner should consolidate its investment in a limited partnership or similar entity. The provisions of EITF 04-5 were required to be applied beginning June 30, 2005 by general partners of all newly formed limited partnerships and for existing limited partnerships for which the partnership agreements are modified and is effective for general partners in all other limited partnerships beginning January 1, 2006. The Company is currently evaluating existing relationships to determine the impact that EITF 04-5 may have on its results of operations and financial condition.

Note 4.  Operating Revenue
The Company's operating revenue consists of the following:

	Three Months     Ended June 30,		Six Months     Ended June 30,
	2005	2004	2005	2004
	(millions)
Operating Revenue
Regulated gas sales	$217	$183	$995	$843
Nonregulated electric sales	77	100	154	188
Nonregulated gas sales
External customers	239	148	654	511
Affiliated customers	206	271	458	564
Gas transportation and storage	189	165	469	437
Gas and oil production	355	317	711	613
Other	286	117	501	223
Total operating revenue	$1,569	$1,301	$3,942	$3,379

PAGE 10

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 5.  Comprehensive Income
The following table presents total comprehensive income (loss):

	Three Months     Ended June 30,		Six Months     Ended June 30,
	2005	2004	2005	2004
	(millions)
Net income	$251	$182	$538	$493
Other comprehensive 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(1)	(13)	(76)	(675)	(250)
Other(2)	-	(44)	-	(32)
Other comprehensive loss	(13)	(120)	(675)	(282)
Total comprehensive income (loss)	$  238	$  62	$(137)	$211

________________
⁽¹⁾Primarily due to unfavorable changes in the fair value of certain commodity derivatives resulting from an increase in commodity prices. The increase in commodity prices resulted in an increase in the net derivative liability reported in the Company's Consolidated Balance Sheet as of June 30, 2005.
⁽²⁾Represents primarily the impact of foreign currency translation adjustments.

Note 6.  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 June 30,		Six Months     Ended June 30,
	(millions)
	2005	2004	2005	2004
Portion of gains (losses) on hedging instruments determined to be ineffective and included in net income:
Fair value hedges	$ -	$ (1)	$ 1	-
Cash flow hedges(1)	(7)	4	(12)	$     1
Net ineffectiveness	$ (7)	$  3	$ (11)	$ 1
Portion of gains (losses) on hedging instruments excluded from measurement of effectiveness and included in net income:
Cash flow hedges(2)	$ (2)	$ 38	$ (1)	$ 74

(1)Represents an increase in hedge ineffectiveness expense primarily due to an increase in the fair value differential between the delivery location and commodity specifications of derivatives held by exploration and production operations and the delivery location and commodity specifications of the Company's forecasted gas and oil sales.
⁽²⁾Amounts relate to changes in options' time value.

 PAGE 11

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

The following table presents selected information related to cash flow hedges included in accumulated other comprehensive income (loss) (AOCI) in the Consolidated Balance Sheet at June 30, 2005:

	AOCI After-Tax	Portion Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	Maximum Term
	(millions)
Commodities:
Gas	$   (909)	$(452)	63 months
Oil	(615)	(289)	42 months
Interest Rate	(1)	-	113 months
Total	$(1,525)	$(741)

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

As a result of a delay in reaching anticipated production levels in the Gulf of Mexico, the Company discontinued hedge accounting for certain cash flow hedges related to forecasted oil production effective March 1, 2005. In connection with the discontinuance of hedge accounting for these contracts, the Company reclassified $30 million ($19 million after-tax) of losses from AOCI to earnings in March 2005. Through June 30, 2005, the Company has recognized additional losses of $17 million ($11 million after-tax) due to subsequent changes in the fair value of these contracts. These amounts were reported in other operations and maintenance expense in the Consolidated Statements of Income.

Note 7.  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, 2005.

Note 8.  Variable Interest Entities
In accordance with FASB Interpretation No. 46 (revised December 2003),Consolidation of Variable Interest Entities, (FIN 46R), the Company consolidates a variable interest lessor entity through which the Company has financed and leased a power generation project. The Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004 reflect net property, plant and equipment of $211 million and $214 million, respectively, and $234 million of debt related to this entity. The debt is nonrecourse to the Company and is secured by the entity's property, plant and equipment.

PAGE 12

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 9.  Significant Financing Transactions
Joint Credit Facilities
In May 2005, Dominion, Virginia Electric and Power Company (Virginia Power), a wholly-owned subsidiary of Dominion, and the Company entered into a $2.5 billion five-year revolving credit facility that replaced their $1.5 billion three-year facility dated May 2004 and their $750 million three-year facility dated May 2002. This credit facility is being used for working capital, as support for the combined commercial paper programs of Dominion, Virginia Power and the Company and other general corporate purposes. This credit facility can also be used to support up to $1.25 billion of letters of credit. At June 30, 2005, total outstanding commercial paper supported by the joint credit facility was $1.3 billion, none of which were the Company's borrowings. At June 30, 2005, total outstanding letters of credit supported by the joint credit facility was $493 million, $30 million of which was issued on behalf of the Company.

At June 30, 2005, capacity available under this credit facility was $739 million.

Other Credit Facilities
The Company utilizes cash and letters of credit to fund collateral requirements under its commodities hedging program. Collateral requirements are impacted by commodity prices, hedging levels and the credit quality of the Company and its counterparties. In August 2004, the Company entered into a $1.5 billion three-year revolving credit facility that terminates in August 2007. This credit facility is being used to support the issuance of commercial paper and letters of credit to provide collateral required by counterparties on derivative financial contracts used by the Company in its risk management strategies for its gas and oil production. At June 30, 2005, outstanding letters of credit under this facility totaled $941 million. The Company expects to replace this facility with a five-year $1.75 billion facility in the third quarter of 2005.

In addition to the facilities above, in June and August of 2004, the Company entered into two $100 million letter of credit agreements that terminate in June 2007 and August 2009, respectively. Additionally, in October 2004, the Company entered into three letter of credit agreements totaling $700 million that were scheduled to terminate in April 2005. Due to the recent volatility in commodity prices and the related impact on collateral requirements, the Company extended these agreements to October 2005. These five agreements support letter of credit issuances, providing collateral required on derivative financial contracts used by the Company in its risk management strategies for gas and oil production. At June 30, 2005, outstanding letters of credit under these agreements totaled $900 million.

Long-Term Debt
In April 2005, the Company repaid $150 million of its 7.375% debentures.

Shelf Registration
At June 30, 2005, the Company had $900 million of available capacity under a shelf registration with the SEC that would permit the Company to issue debt and trust preferred securities to meet future capital requirements.

Note 10.  Commitments and Contingencies
Other than the matters discussed below, there have been no significant developments regarding commitments and contingencies disclosed in Note 19 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2004, or Note 11 to the Consolidated Financial Statements in the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, nor have any significant new matters arisen during the three months ended June 30, 2005.

PAGE 13

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Guarantees, Letters of Credit and Surety Bonds
As of June 30, 2005, the Company had issued $2.0 billion of guarantees, including: $1.6 billion to support commodity transactions of subsidiaries; $200 million for subsidiary debt and $193 million for guarantees supporting other agreements of subsidiaries. The Company had also purchased $43 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $1.9 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 beha lf of its subsidiaries in the Consolidated Financial Statements, unless it becomes probable that the Company will have to perform under the guarantees. No such liabilities have been recognized as of June 30, 2005. 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
As a result of its large and diverse customer base, the Company is not exposed to a significant concentration of credit risk for receivables arising from gas utility operations and retail energy sales. The Company's exposure to credit risk is concentrated primarily within its sales of gas and oil production and energy marketing, including its hedging activities, as the Company transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. At June 30, 2005, gross credit exposure related to these transactions totaled $450 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 62% and no single counterparty exceeded 7%. The Company held $1 million of collateral at June 30, 2005.

As of June 30, 2005 and December 31, 2004, the Company had margin deposit assets (reported in other current assets) of $329 million and $88 million, respectively. The Company had margin deposit liabilities (reported in other current liabilities) of $1 million as of June 30, 2005. The Company had no margin deposit liabilities at December 31, 2004.

Note 12.    Related Party Transactions
The Company engages in related party transactions primarily with affiliates (Dominion subsidiaries). The Company's accounts receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. The Company is included in Dominion's consolidated federal income tax return and participates in certain Dominion benefit plans. The significant related party transactions are disclosed below.

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

PAGE 14

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Presented below are affiliated transactions recorded in operating revenue and operating expenses:

	Three Months     Ended June 30,		Six Months     Ended June 30,
	2005	2004	2005	2004
	(millions)
Purchases of natural gas from affiliates	$163	$129	$296	$279
Purchases of electric fuel and energy from affiliates	43	53	88	91
Sales of natural gas to affiliates	206	271	458	564
Sales of gas transportation and storage services to affiliates	3	5	9	12
Sales of electricity to affiliates	7	14	9	22

The commodity transactions reported above include net realized gains and (losses) on affiliated commodity transactions of $(2) million and $7 million in the second quarters of 2005 and 2004, respectively, and $(13) million and $10 million in the first six months of 2005 and 2004, respectively. At June 30, 2005 and December 31, 2004, the Company's Consolidated Balance Sheets include derivative assets of $322 million and $249 million, respectively, and derivative liabilities of $54 million and $49 million, respectively, with affiliates. 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 AOCI on the Consolidated Balance Sheets.

Dominion Resources Services, Inc. provides certain administrative and technical services to the Company, which totaled $45 million and $39 million in the second quarters of 2005 and 2004, respectively, and $90 million and $83 million for the six months ended June 30, 2005 and 2004, respectively. The Company provides certain services to affiliates, including technical services, which totaled $2 million in both the second quarters of 2005 and 2004, and $3 million and $4 million for the six months ended June 30, 2005 and 2004, respectively.

Transactions with Dominion
The Company and its subsidiaries have borrowed funds from Dominion. In February 2005, borrowings by certain Company subsidiaries from Dominion under short-term demand notes were converted to borrowings under the Dominion money pool. At June 30, 2005 and December 31, 2004, the Company's subsidiaries had outstanding borrowings, net of repayments, under the Dominion money pool totaled $1.9 billion and $1.0 billion, respectively. The short-term demand note borrowings were $163 million at December 31, 2004. Interest charges incurred by the Company related to these borrowings were $12 million and $3 million in the second quarters of 2005 and 2004, respectively, and $20 million and $5 million for the six months ended June 30, 2005 and 2004, respectively.

PAGE 15

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:

	Pension Benefits		Other Postretirement Benefits
	2005	2004	2005	2004
Three Months Ended June 30,	(millions)
Service cost	$ 3	$ 2	$ 3	$ 5
Interest cost	7	7	6	7
Expected return on plan assets	(25)	(25)	(4)	(4)
Amortization of prior service cost	1	-	-	-
Amortization of transition obligation	-	-	2	2
Amortization of net loss	-	-	2	2
Net periodic benefit cost (credit)	$(14)	$(16)	$9	$12
Company's net periodic benefit cost (credit)(1)	$(26)	$(28)	$ 12	$17
Six Months Ended June 30,
Service cost	$ 6	$  5	$ 7	$  9
Interest cost	15	15	12	13
Expected return on plan assets	(51)	(50)	(8)	(7)
Amortization of prior service cost	1	-	-	-
Amortization of transition obligation (asset)	-	(1)	3	3
Amortization of net loss	-	-	3	5
Net periodic benefit cost (credit)	$(29)	$(31)	$17	$23
Company's net periodic benefit cost (credit)(1)	$(51)	$(56)	$ 24	$32

(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 2005. The Company expects to contribute at least $40 million to its other postretirement benefit plans during the remainder of 2005. Under its funding policies, the Company evaluates pension and other postretirement benefit plan funding requirements annually, usually in the second half of the year 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 2005 will be determined at that time.

PAGE 16

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 14.  Condensed Consolidating Financial Information
The Company has fully and unconditionally guaranteed $200 million of senior notes issued by its wholly-owned subsidiary, Dominion Oklahoma Texas Exploration and Production, Inc. (DOTEPI). In the event of a default by this subsidiary, the Company would be obligated to repay such amounts. Condensed consolidating financial information for the Company, DOTEPI and the Company's other subsidiaries are presented below:

Condensed Consolidating Statement of Income Information

Three Months Ended June 30, 2005	CNG (ParentCompany)	DOTEPI	OtherSubsidiaries	Adjustments & Eliminations	Consolidated
	(millions)
Operating revenue	$     -	$180	$1,508	$(119)	$1,569
Operating expense	1	95	1,150	(113)	1,133
Income (loss) from operations	(1)	85	358	(6)	436
Other income	50	-	11	(52)	9
Interest and related charges	48	16	40	(51)	53
Income before income taxes	1	69	329	(7)	392
Income tax expense	-	23	120	(2)	141
Equity in earnings of subsidiaries	250	-	-	(250)	-
Net income	$251	$  46	$  209	$(255)	$  251

Six Months Ended June 30, 2005	CNG (ParentCompany)	DOTEPI	OtherSubsidiaries	Adjustments & Eliminations	Consolidated
	(millions)
Operating revenue	$     -	$353	$3,842	$(253)	$3,942
Operating expense	1	194	3,055	(245)	3,005
Income (loss) from operations	(1)	159	787	(8)	937
Other income	99	-	14	(101)	12
Interest and related charges	100	31	75	(101)	105
Income (loss) before income taxes	(2)	128	726	(8)	844
Income tax expense (benefit)	(2)	43	268	(3)	306
Equity in earnings of subsidiaries	538	-	-	(538)	-
Net income	$538	$  85	$  458	$(543)	$  538

PAGE 17

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Three Months Ended June 30, 2004	CNG (ParentCompany)	DOTEPI	OtherSubsidiaries	Adjustments & Eliminations	Consolidated
	(millions)
Operating revenue	$     -	$153	$1,270	$(122)	$1,301
Operating expense	1	73	1,026	(125)	975
Income (loss) from operations	(1)	80	244	3	326
Other income	42	-	13	(44)	11
Interest and related charges	48	10	28	(45)	41
Income (loss) before income taxes	(7)	70	229	4	296
Income tax expense (benefit)	(2)	11	103	2	114
Equity in earnings of subsidiaries	187	-	-	(187)	-
Net income	$182	$  59	$  126	$(185)	$  182

Six Months Ended June 30, 2004	CNG (ParentCompany)	DOTEPI	OtherSubsidiaries	Adjustments & Eliminations	Consolidated
	(millions)
Operating revenue	$     -	$291	$3,350	$(262)	$3,379
Operating expense	1	151	2,668	(262)	2,558
Income (loss) from operations	(1)	140	682	-	821
Other income	92	-	37	(89)	40
Interest and related charges	98	20	55	(90)	83
Income (loss) before income taxes	(7)	120	664	1	778
Income tax expense (benefit)	(3)	30	257	1	285
Equity in earnings of subsidiaries	497	-	-	(497)	-
Net income	$493	$  90	$  407	$(497)	$  493

PAGE 18

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Condensed Consolidating Balance Sheet Information

At June 30, 2005	CNG (ParentCompany)	DOTEPI	OtherSubsidiaries	Adjustments & Eliminations	Consolidated
	(millions)
Assets
Current assets	$1,875	$   393	$3,978	$(2,615)	$3,631
Investment in affiliates	3,431	-	153	(3,368)	216
Loan to affiliates	2,202	-	-	(2,202)	-
Property, plant and equipment, net	-	3,842	7,977	(86)	11,733
Deferred charges and other assets	331	532	2,887	(517)	3,233
Total assets	$7,839	$4,767	$14,995	$(8,788)	$18,813
Liabilities & Shareholder's Equity
Current liabilities	$  334	$1,326	$6,794	$(2,613)	$5,841
Long-term debt	3,012	204	234	-	3,450
Notes payable to affiliates	206	1,089	1,114	(2,203)	206
Deferred credits and other liabilities	266	1,119	4,475	(566)	5,294
Common shareholder's equity	4,021	1,029	2,378	(3,406)	4,022
Total liabilities and shareholder's            equity	$7,839	$4,767	$14,995	$(8,788)	$18,813

At December 31, 2004	CNG (ParentCompany)	DOTEPI	OtherSubsidiaries	Adjustments & Eliminations	Consolidated
	(millions)
Assets
Current assets	$1,866	$   341	$3,047	$(2,625)	$2,629
Investment in affiliates	3,891	-	141	(3,828)	204
Loan to affiliates	2,202	-	-	(2,202)	-
Property, plant and equipment, net	-	3,619	7,506	(75)	11,050
Deferred charges and other assets	225	532	2,450	(368)	2,839
Total assets	$8,184	$4,492	$13,144	$(9,098)	$16,722
Liabilities & Shareholder's Equity
Current liabilities	$  379	$1,047	$5,408	$(2,622)	$4,212
Long-term debt	3,014	206	234	-	3,454
Notes payable to affiliates	206	1,089	1,113	(2,202)	206
Deferred credits and other liabilities	105	1,093	3,582	(410)	4,370
Common shareholder's equity	4,480	1,057	2,807	(3,864)	4,480
Total liabilities and shareholder's            equity	$8,184	$4,492	$13,144	$(9,098)	$16,722

PAGE 19

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Condensed Consolidating Statement of Cash Flow Information

Six Months Ended June 30, 2005	CNG (ParentCompany)	DOTEPI	OtherSubsidiaries	Adjustments & Eliminations	Consolidated
	(millions)
Net cash provided by operating      activities	$331	$67	$593	$(389)	$602
Net cash provided by (used in)      investing activities	144	(272)	(577)	(128)	(833)
Net cash provided by (used in)      financing activities	(474)	201	(18)	516	225

Six Months Ended June 30, 2004	CNG (ParentCompany)	DOTEPI	OtherSubsidiaries	Adjustments & Eliminations	Consolidated
	(millions)
Net cash provided by operating      activities	$266	$312	$774	$(261)	$1,091
Net cash provided by (used in)      investing activities	156	(296)	(97)	22	(215)
Net cash used in financing      activities	(423)	(23)	(680)	240	(886)

Note 15.  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:

Delivery includes the Company's regulated gas distribution systems which are subject to cost-of-service rate regulation and accordingly, applies SFAS No. 71,Accounting for the Effects of Certain Types of Regulation.It also includes the customer service operations and the Company's nonregulated retail energy marketing activities.

Energy includes the Company's tariff-based natural gas transmission pipeline and storage businesses and an LNG facility which are subject to cost-of-service rate regulation and accordingly, applies SFAS No. 71. It also includes certain natural gas production and producer services, which consist of aggregation of gas supply and related wholesale activities.

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

PAGE 20

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

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

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

	Delivery	Energy	Exploration & Production	Corporate and Other	Eliminations	ConsolidatedTotal
	(millions)
Three Months ended June 30, 2005
Operating revenue - external and affiliated customers	$437	$475	$651	$ 6	$  -	$1,569
Operating revenue - intersegment	7	55	38	-	(100)	-
Net income	17	49	185	-	-	251
Three Months ended June 30, 2004
Operating revenue - external and affiliated customers	$391	$463	$430	$ 17	$  -	$1,301
Operating revenue - intersegment	15	52	34	-	(101)	-
Net income (loss)	28	38	144	(28)	-	182
Six Months Ended June 30, 2005
Operating revenue - external and affiliated customers	$1,671	$1,038	$1,223	$ 10	$  -	$3,942
Operating revenue - intersegment	23	115	72	-	(210)	-
Net income	120	129	289	-	-	538
Six Months Ended June 30, 2004
Operating revenue - external and affiliated customers	$1,521	$1,029	$802	$ 27	$  -	$3,379
Operating revenue - intersegment	34	111	68	-	(213)	-
Net income (loss)	127	121	253	(8)	-	493

PAGE 21

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 Consolidated Natural Gas 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 reader will find the following information in this MD&A:

• Forward-Looking Statements
• Accounting Matters
• Results of Operations
• Segment Results of Operations
• Credit Risk
• 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 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 inRisk 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, 2005, 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, 2004. The policies disclosed included the accounting for: derivative contracts at fair value; use of estimates in goodwill testing; employee benefit plans; regulated operations; gas and oil operations; and income taxes.

PAGE 22

CONSOLIDATED NATURAL GAS COMPANY

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

Other
As discussed in Note 2 to the Consolidated Financial Statements, the Company enters into buy/sell and related agreements as a means to reposition its offshore Gulf of Mexico crude oil production to more liquid marketing locations onshore. Under the primary guidance of EITF Issue No. 99-19, the Company presents the sales and purchases related to its crude oil buy/sell arrangements on a gross basis in its Consolidated Statements of Income. The EITF is currently discussing Issue No. 04-13, which specifically focuses on purchase and sale transactions made pursuant to crude oil buy/sell arrangements. The EITF has issued for comment a draft abstract that would require these transactions to be presented on a net basis in the Consolidated Statements of Income. While resolution of this issue may affect the income statement presentation of these revenues and expenses, there would be no impact on the Company's results of operations or cash flows. The portion of the Company's operating revenue from external cust omers related to buy/sell activity for the second quarter and year-to-date period ended June 30, 2005 was approximately 6% and 5%, respectively, and for the second quarter and year-to-date period ended June 30, 2004 was approximately 6% and 4%, respectively. Reported production volumes are not impacted, as only the initial sale of the Company's production is included in reported production volumes. It is estimated that for the second quarter and year-to-date period ended June 30, 2005, approximately 47% and 49%, respectively, of the Company's oil production was marketed through the use of one or more crude oil buy/sell agreements.

Results of Operations
Segment results include the impact of intersegment revenues and expenses, which may result in an intersegment profit or loss. Following is a summary of contributions by the Company's operating segments to net income for the second quarter and year-to-date period ended June 30, 2005 and 2004:

	Second Quarter		Year-To-Date
	2005	2004	2005	2004
	(millions)
Delivery	$ 17	$ 28	$ 120	$ 127
Energy	49	38	129	121
Exploration & Production	185	144	289	253
Primary operating segments	251	210	538	501
Corporate and Other	-	(28)	-	(8)
Consolidated net income	$251	$182	$538	$493

Overview

Second Quarter 2005 vs. 2004
Net income for the second quarter of 2005 increased 38% to $251 million, as compared to the second quarter of 2004. This increase largely reflects:

• A lower contribution from the delivery operations, primarily reflecting the favorable impact in the prior year of a reduction in bad debt reserves and higher interest expense for the regulated operations;
• A higher contribution from energy operations reflecting higher income from gas transmission operations and higher gas prices at producer services; and
• A higher contribution from exploration and production operations due to the final settlement of business interruption insurance claims associated with Hurricane Ivan and higher average realized gas and oil prices, partially offset by the impact in the prior year of favorable changes in the fair value of certain oil options and higher expenses related to other operations and maintenance and interest expense.

Year-To-Date 2005 vs. 2004
Net income for the six months ended June 30, 2005 increased 9% to $538 million, as compared to the first six months of 2004. This increase largely reflects:

• A lower contribution from delivery operations reflecting higher gas margins for the nonregulated retail energy marketing operations, offset by higher bad debt and interest expenses for the regulated operations;
• A higher contribution from energy operations reflecting primarily higher gas prices at producer services; and

PAGE 23

CONSOLIDATED NATURAL GAS COMPANY

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

• A higher contribution from exploration and production operations reflecting:
• The recognition of business interruption insurance revenue associated with Hurricane Ivan;
• An increase in revenue recognized in connection with deliveries under volumetric production payment (VPP) agreements offset by lower gas production;
• Higher average realized gas and oil prices; partially offset by
• Prior year favorable changes in the fair value of certain oil options;
• Losses related to the discontinuance of hedge accounting for certain oil hedges primarily resulting from a delay in reaching anticipated production levels in the Gulf of Mexico and subsequent changes in the fair value of those hedges;
• Higher depreciation, depletion and amortization expense; and
• Higher operating costs and interest expense in 2005.

Net income for Corporate and Other was impacted by the disposition of CNGI's investment in an Australian pipeline business that was sold in the second quarter of 2004.

Analysis of Consolidated Operations

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

	Second Quarter		Year-To-Date
	2005	2004	2005	2004
	(millions)
Operating Revenue
Regulated gas sales	$ 217	$ 183	$ 995	$ 843
Nonregulated electric sales(1)	77	100	154	188
Nonregulated gas sales(1)	445	419	1,112	1,075
Gas transportation and storage(1)	189	165	469	437
Gas and oil production	355	317	711	613
Other(1)	286	117	501	223
Operating Expenses
Purchased gas, net(1)	548	500	1,723	1,564
Electric fuel and energy purchases(1)	67	88	139	168
Liquids, pipeline capacity and    other purchases	86	58	188	109
Other operations and maintenance(1)	203	121	470	273
Depreciation, depletion and amortization	169	154	335	308
Other taxes	60	54	150	136
Other income	9	11	12	40
Interest and related charges(1)	53	41	105	83
Income tax expense	141	114	306	285

 ⁽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.

PAGE 24

CONSOLIDATED NATURAL GAS COMPANY

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

An analysis of the Company's results of operations for the second quarter and the year-to-date period of 2005 compared to the second quarter and the year-to-date period of 2004 follows:

Second Quarter 2005 vs. 2004

Operating Revenue

Regulated gas sales revenue increased 19% to $217 million, largely resulting from a $34 million increase primarily related to the recovery of higher gas prices. The effect of this increase was largely offset by a comparable increase inPurchased gas, net expense.

Nonregulated electric sales revenue decreased 23% to $77 million, primarily reflecting the combined effects of:

• A $15 million decrease in revenue from nonregulated retail energy marketing operations, due to lower volumes ($38 million) reflecting a decrease in average customer accounts, partially offset by higher prices ($23 million); and
• A $7 million decrease in revenue from the Company's power generation facility due to lower volumes.

Nonregulated gas sales revenue increased 6% to $445 million, which was largely offset by a corresponding increase inPurchased gas, net expense. This increase primarily reflects:

• A $19 million increase in revenue from nonregulated retail energy marketing operations, primarily due to higher prices; and
• A $15 million increase in revenue from sales of gas purchased by exploration and production operations to facilitate gas transportation and satisfy other agreements; partially offset by
• A $10 million decrease in revenue from gas aggregation activities, reflecting lower volumes ($56 million), partially offset by higher prices ($46 million).

Gas transportation and storage revenue increased 15% to $189 million, primarily reflecting a $19 million increase in revenue from gas transmission operations largely due to additions of pipeline and storage capacity.

Gas and oil production revenue increased 12% to $355 million, primarily as a result of:

• A $34 million increase in revenue from oil production, largely reflecting higher volumes; and
• A $7 million increase in revenue recognized related to deliveries under VPP transactions, reflecting higher volumes ($11 million) and lower prices ($4 million); partially offset by
• A $2 million decrease in revenue from gas production, reflecting lower volumes ($26 million) largely due to the sale of mineral rights under the VPP agreements, partially offset by higher average realized prices ($24 million).

Other revenue increased 144% to $286 million, primarily reflecting:

• A $135 million increase due to the final settlement of business interruption insurance claims associated with Hurricane Ivan;
• A $22 million increase in revenue from sales of purchased oil by exploration and production operations. This increase was offset by a corresponding increase inLiquids, pipeline capacity and other purchases expense; and  
• A $12 million increase in sales of extracted products principally due to increased volumes.

PAGE 25

CONSOLIDATED NATURAL GAS COMPANY

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

Operating Expenses and Other Items

Purchased gas, net expenseincreased 10% to $548 million, principally resulting from:

• A $32 million increase associated with regulated gas distribution operations discussed above inRegulated gas sales revenue;
• A $19 million increase related to nonregulated retail energy marketing operations discussed inNonregulated gas sales revenue; and
• A $15 million increase associated with exploration and production operations discussed inNonregulated gas sales revenue; partially offset by
• An $18 million decrease associated with gas aggregation activities reflecting lower volumes ($56 million), partially offset by higher prices ($38 million).

Electric fuel and energy purchases expense decreased 24% to $67 million, primarily due to a $10 million decrease related to nonregulated retail energy marketing operations reflecting lower volumes ($34 million) partially offset by higher prices ($24 million) and lower generation volumes ($11 million) for the Company's power generating facility.

Liquids, pipeline capacity and other purchases expense increased 48% to $86 million, reflecting primarily a $24 million increase related to purchases of oil by exploration and production operations, as discussed above inOther revenue.

Other operations and maintenance expense increased 68% to $203 million, primarily reflecting the following:

• A $38 million benefit in 2004 due to favorable changes in the fair value of certain oil options related to exploration and production operations. No comparable benefit was recognized during 2005;
• A $12 million increase in hedge ineffectiveness expense primarily due to an increase in the fair value differential between the delivery location and commodity specifications of derivatives held by exploration and production operations and the delivery location and commodity specifications of the Company's forecasted gas and oil sales;
• A $20 million increase in other costs related to gas and oil production activities such as administrative costs and financing fees; and
• A $6 million increase due to higher bad debt expense associated with gas distribution operations primarily reflecting the favorable impact in the prior year of a reduction in reserves.

Depreciation, depletion and amortization expense (DD&A) increased 10% to $169 million, primarily reflecting higher exploration and production finding and development costs and the impact of increased oil production.

Other taxes increased 11% to $60 million, primarily due to higher severance and property taxes due to increased revenue resulting from higher commodity prices.

Interest expense increased 29% to $53 million, primarily reflecting:

• A $10 million increase related to Dominion money pool borrowings due principally to higher outstanding balances; and
• A $3 million increase due to the effect of higher interest rates in 2005 on variable rate instruments.

Income taxes-The Company's effective tax rate decreased by 2.3% to 36.0%, primarily due to adjustments to a valuation allowance related to CNGI investments in the second quarter of 2004, partially offset by a favorable state income tax adjustment.

PAGE 26

CONSOLIDATED NATURAL GAS COMPANY

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

Year-To-Date 2005 vs. 2004

Operating Revenue

Regulated gas sales revenue increased 18% to $995 million, largely resulting from a $128 million increase primarily related to the recovery of higher gas prices and a $72 million increase resulting from the return of customers from Energy Choice programs, partially offset by a $29 million decrease associated with milder weather, changes in customer usage and other factors. The effect of this net increase was largely offset by a comparable increase inPurchased gas, net expense.

Nonregulated electric sales revenue decreased 18% to $154 million, primarily reflecting the combined effects of:

• A $21 million decrease in revenue from nonregulated retail energy marketing operations, due to lower volumes ($58 million) reflecting a decrease in average customer accounts, partially offset by higher prices ($37 million); and
• A $13 million decrease in revenue from the Company's power generation facility due to lower volumes.

Nonregulated gas sales revenue increased 3% to $1.1 billion, which was largely offset by a corresponding increase inPurchased gas, net expense. This increase primarily reflects:

• A $56 million increase in revenue from sales of gas purchased by exploration and production operations to facilitate gas transportation and satisfy other agreements; partially offset by
• A $15 million decrease in revenue from gas aggregation activities, due to lower volumes ($100 million), partially offset by higher prices ($85 million); and
• A $4 million decrease in revenue from nonregulated retail energy marketing operations, due to lower volumes ($66 million) reflecting a decrease in average customer accounts, largely offset by higher prices ($62 million).

Gas transportation and storage revenue increased 7% to $469 million, primarily reflecting a $30 million increase in revenue from gas transmission operations largely due to additions of pipeline and storage capacity.

Gas and oil production revenue increased 16% to $711 million, primarily as a result of:

• A $69 million increase in revenue from oil production, largely reflecting higher volumes; and
• A $45 million increase in revenue recognized related to deliveries under VPP transactions primarily due to higher volumes; partially offset by
• An $18 million decrease in revenue from gas production, reflecting lower volumes ($63 million) largely due to the sale of mineral rights under the VPP agreements, partially offset by higher average realized prices ($45 million).

Other revenue increased 125% to $501 million, primarily reflecting:

• A $179 million increase due to the recognition of business interruption insurance revenue associated with Hurricane Ivan;
• A $69 million increase in revenue from sales of purchased oil by exploration and production operations. This increase was offset by a corresponding increase inLiquids, pipeline capacity and other purchases expense; and  
• A $29 million increase in sales of extracted products principally due to increased volumes.

 PAGE 27

CONSOLIDATED NATURAL GAS COMPANY

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

Operating Expenses and Other Items

Purchased gas, net expenseincreased 10% to $1.7 billion, principally resulting from:

• A $153 million increase associated with regulated gas distribution operations discussed above inRegulated gas sales revenue;
• A $56 million increase related to exploration and production operations discussed inNonregulated gas sales revenue; partially offset by
• A $28 million decrease associated with gas aggregation activities reflecting lower volumes ($100 million), partially offset by higher prices ($72 million); and
• A $19 million decrease associated with nonregulated retail energy marketing operations, reflecting decreased volumes ($62 million) partially offset by higher prices ($43 million).

Electric fuel and energy purchases expense decreased 17% to $139 million, primarily reflecting:

• A $15 million decrease related to nonregulated retail energy marketing operations due to lower volumes ($52 million) reflecting a decrease in average customer accounts partially offset by higher prices ($37 million); and
• A $14 million decrease due to lower generation volumes for the Company's power generating facility.

Liquids, pipeline capacity and other purchases expense increased 72% to $188 million, reflecting primarily a $70 million increase related to purchases of oil by exploration and production operations, as discussed above inOther revenue.

Other operations and maintenance expense increased 72% to $470 million, primarily resulting from:

• $47 million of losses related to the discontinuance of hedge accounting for certain oil hedges primarily resulting from a delay in reaching anticipated production levels in the Gulf of Mexico, and subsequent changes in the fair value of those hedges;
• A $75 million benefit in 2004 due to favorable changes in the fair value of certain oil options related to exploration and production operations. No comparable benefit was recognized during 2005;
• A $12 million increase in hedge ineffectiveness expense primarily due to an increase in the fair value differential between the delivery location and commodity specifications of derivatives held by exploration and production operations and the delivery location and commodity specifications of the Company's forecasted gas and oil sales;
• A $39 million increase in costs related to gas and oil production activities related to higher production costs, administrative costs and financing fees; and
• A $15 million increase due to higher bad debt expense associated with gas distribution operations primarily reflecting the favorable impact in the prior year of a reduction in reserves.

Depreciation, depletion and amortization expense increased 9% to $335 million, primarily reflecting higher exploration and production finding and development costs and the impact of increased oil production.

Other taxes increased 10% to $150 million, primarily due to higher gross receipts taxes and higher severance and property taxes due to increased revenues resulting from higher commodity prices.

Other incomedecreased 70% to $12 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 recognized in 2004 resulting from a favorable adjustment to the carrying amount of this investment in 2004. No comparable benefit was recognized during 2005.

Interest expense increased 27% to $105 million, primarily reflecting:

• A $15 million increase related to Dominion money pool borrowings due principally to higher outstanding balances; and
• A $7 million increase due to the effect of higher interest rates in 2005 on variable rate instruments.

PAGE 28

CONSOLIDATED NATURAL GAS COMPANY

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

Segment Results of Operations

Delivery Segment

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

	Second Quarter		Year-To-Date
	2005	2004	2005	2004
	(millions)
Net income contribution	$17	$28	$120	$127
Throughput (bcf):
Gas sales-regulated	20	16	83	78
Gas transportation-regulated	44	46	136	144
Total throughput	64	62	219	222
bcf = billion cubic feet

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

	Second Quarter 2005 vs. 2004 Increase (Decrease)	Year-To-Date 2005 vs. 2004Increase (Decrease)
	(millions)
Nonregulated retail energy marketing operations	$ (3)	$ 10
Weather	4	3
Bad debt reserve	(4)	(6)
Interest expense	(4)	(7)
Other margins	(4)	(5)
Other	-	(2)
Change in net income contribution	$(11)	$(7)

Delivery's second quarter and year-to-date net income contribution decreased $11 million and $7 million, respectively, primarily reflecting:

• A lower contribution from nonregulated retail energy marketing operations in the second quarter, largely resulting from a decrease in average customer accounts; partially offset by higher gas and electric margins. In the year-to-date period, the contribution from nonregulated retail energy marketing operations increased, largely resulting from higher gas margins;
• Favorable weather in the regulated gas service territories;
• Higher bad debt expense, reflecting primarily the favorable impact in the prior year of a reduction in reserves;
• Increased interest expense primarily due to higher rates on Dominion money pool borrowings and on additional long-term debt borrowings from the parent company;
• Lower contributions from regulated gas operations, reflecting the changes in customer usage and other factors; and
• Other factors including an increase in incentive based compensation and medical benefits expense.

PAGE 29

CONSOLIDATED NATURAL GAS COMPANY

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

Energy Segment

Energy includes the Company's tariff-based natural gas transmission pipeline and storage businesses and an LNG facility. It also includes certain natural gas production operations and producer services, which consist of aggregation of gas supply and related wholesale activities.

	Second Quarter		Year-To-Date
	2005	2004	2005	2004
	(millions)
Net income contribution	$49	$38	$129	$121
Gas sales (bcf)	50	59	111	127
Gas transmission throughput (bcf)	134	107	434	423

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

	Second Quarter 2005 vs. 2004 Increase (Decrease)	Year-To-Date 2005 vs. 2004Increase (Decrease)
	(millions)
Producer services	$ 4	$ 6
Cove Point	3	4
Gas transmission operations	4	(2)
Change in net income contribution	$11	$ 8

Energy's second quarter and year-to-date net income contribution increased $11 million and $8 million, respectively, primarily reflecting:

• Higher gas prices realized by the producer services operation;
• Higher contribution realized from the Cove Point LNG facility resulting from the addition of a fifth storage tank in December 2004 and increased pipeline capacity; and
• Higher gas transportation and storage revenue due primarily to incremental revenue from additional pipeline capacity and by-product sales, partially offset by higher gas expense and lower volumes of gas production. In the year-to-date period, higher gas transportation and storage revenue and by-product sales were offset by higher gas expense and lower volumes of gas production.

PAGE 30

CONSOLIDATED NATURAL GAS COMPANY

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

Exploration & Production Segment

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

	Second Quarter		Year-To-Date
	2005	2004	2005	2004
	(millions)
Net income contribution	$185	$144	$289	$253
Gas production (bcf)	62.4	67.0	126.1	136.6
Oil production (million bbls)	3.4	2.1	6.3	4.0
Average realized prices with hedging results:
Gas (per mcf)(1)	$4.51	$4.05	$4.44	$4.07
Oil (per bbl)	$25.31	$25.24	$26.47	$24.78
��
Average realized prices without hedging results:
Gas (per mcf)(1)	$6.80	$5.67	$6.50	$5.57
Oil (per bbl)	$49.75	$37.40	$49.14	$35.78
Other information:
DD&A (unit of production rate per mcfe)	$1.47	$1.37	$1.47	$1.36

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

(1) Excludes $58 million and $51 million of revenue recognized in the second quarter of 2005 and 2004, respectively, and $125 million and $80 million of revenue recognized in the year-to-date period of 2005 and 2004, respectively, under the VPP agreements described in Note 4 to the Consolidated Financial Statements in the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 and Note 10 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2004.

PAGE 31

CONSOLIDATED NATURAL GAS COMPANY

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

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

	Second Quarter 2005 vs. 2004 Increase (Decrease)	Year-To-Date 2005 vs. 2004Increase (Decrease)
	(millions)
Business interruption insurance	$ 86	$ 114
VPP revenue	4	29
Gas and oil-prices	16	35
Gas and oil-production	6	2
Operations and maintenance expense	(47)	(115)
Depreciation, depletion and amortization expense	(8)	(15)
Interest expense	(6)	(9)
Income tax expense	(16)	(13)
Other	6	8
Change in net income contribution	$ 41	$ 36

Exploration & Production's second quarter and year-to-date net income contribution increased $41 million and $36 million, respectively, primarily reflecting:

• Recognition of business interruption insurance revenue associated with Hurricane Ivan;
• An increase in revenue recognized in connection with deliveries under the VPP agreements;
• Higher average realized prices for gas and oil;
• Higher oil production reflecting production from the deepwater Gulf of Mexico Devils Tower and Front Runner projects partially offset by lower gas production primarily reflecting the sale of mineral rights under the VPP agreements;
• Higher operations and maintenance expenses, primarily due to the impact in the prior year of favorable changes in the fair value of certain oil options, an increase in hedge ineffectiveness expense and an increase in production costs. Higher year-to-date operations and maintenance expenses also reflect the discontinuance of hedge accounting for certain oil hedges largely resulting from delays in reaching anticipated production levels in the Gulf of Mexico, and subsequent changes in the fair value of those hedges;
• Higher depreciation, depletion and amortization expense, primarily reflecting higher industry finding and development costs and the impact of increased oil production;
• Increased interest expense primarily due to the combined impact of additional borrowings and higher interest rates on Dominion money pool borrowings; and
• Higher state income taxes as a result of the impact in 2004 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.

PAGE 32

CONSOLIDATED NATURAL GAS COMPANY

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

Corporate and Other

Corporate and Other includes the Company's corporate and other functions, including the activities of CNGI, the Company's power generating facility and other minor subsidiaries. Presented below are Corporate and Other's operating results for the second quarter and year-to-date period ended June 30, 2005 and 2004:

	Second Quarter		Year-To-Date
	2005	2004	2005	2004
	(millions)
Total net income (loss)	$ -	$  (28)	$ -	$  (8)

Corporate and Other reported net expenses of $28 million for the second quarter of 2004 and net expenses of $8 million for year-to-date 2004. The 2004 results primarily reflect an increase in an income tax valuation allowance related to CNGI investments in the second quarter of 2004, 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 year-to-date net expenses also reflect an $18 million benefit from adjusting the carrying amount of this investment in the first quarter to its then current estimate of fair value.

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, 2005. 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. The Company held $1 million of collateral at June 30, 2005.

	Gross Credit Exposure
	(millions)
Investment grade(1)	$245
Non-investment grade(2)	33
No external ratings:
Internally rated-investment grade(3)	36
Internally rated-non-investment grade(4)	136
Total	$450

________________
(1)   Designations as investment grade are based on minimum credit ratings assigned by Moody's Investors Service (Moody's) and Standard & Poor's Rating Group, a division of the McGraw-Hill Companies, Inc. (Standard & Poor's). The five largest counterparty exposures, combined, for this category represented approximately 23% of the total gross credit exposure.
(2)   The five largest counterparty exposures, combined, for this category represented approximately 5% 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 7% of the total gross credit exposure.

PAGE 33

CONSOLIDATED NATURAL GAS COMPANY

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

Other Matters

Energy Policy Act of 2005 (the Act)

In July 2005, Congress passed the Act and sent it to the President for his signature. The Act includes numerous provisions meant to encourage oil and gas supplies, improve energy system reliability and expand renewable energy sources. The legislation would also repeal the Public Utility Holding Company Act of 1935. The Company is currently evaluating the impact that the Act may have on its results of operations and financial condition.

Dominion Transmission, Inc. (DTI) Rate Matter

In May 2005, the Federal Energy Regulatory Commission (FERC) approved a comprehensive rate settlement with DTI and its customers and interested state commissions. The settlement, which became effective July 1, 2005, reduces the Company's natural gas transportation and storage service revenues by approximately $49 million annually, through a combination of firm transportation rate reductions and reduced fuel retention levels for storage service customers. As part of the settlement, DTI and all signatory parties agreed to a rate moratorium until 2010.

Contract Negotiations with Gas Union

In May 2005, members of the Utility Workers' Union of America, United Gas Workers' Local 69-II, AFL-CIO (Local 69-II) ratified a new three-year contract for the period April 1, 2005 through April 1, 2008. Local 69-II represents approximately 1,000 DTI and Dominion Hope employees.

 PAGE 34

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

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

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

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

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

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

PAGE 35

CONSOLIDATED NATURAL GAS COMPANY

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

For additional information concerning derivatives and commodity-based trading contracts, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk,Market Rate Sensitive Instruments and Risk Management and Notes 2 and 9 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2004.

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

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

An inability to access financial markets could affect the execution of the Company's business plan. The Company relies on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flows from its operations, including margin requirements related to hedges of future gas and oil production. 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 June 30, 2005, the Company's senior unsecured debt is rated BBB+, negative outlook, by Standard & Poor's and A3, stable outlook, by Moody's. Both agencies have implemented more stringent applications of the financial requirements for various ratings levels. In order to maintain its current credit ratings in light of these or future new requirements, the Company may find it necessary to take steps or change its business plans in ways that may adversely affect its growth and earnings. A reduction in the Company's credit ratings by either Standard & Poor's or Moody's could increase its borrowing costs and adversely affect operating results and could require it to post additional margin in connection with some of its marketing activities.

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

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

PAGE 36

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, 2004. The Consolidated Balance Sheet as of June 30, 2005 reflects $212 million of net property, plant and equipment and deferred charges and $234 million of related debt attributable to the SPE. As this SPE is 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 this entity. 

PAGE 37

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.
SeeOther Matters in Management's Discussion and Analysis of Results of Operations for discussion on various regulatory proceedings to which the Company is a party.

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	$2.5 billion Five-Year Revolving Credit Agreement, dated as of May 12, 2005, among Dominion Resources, Inc., Virginia Electric and Power Company, Consolidated Natural Gas Company and JPMorgan Chase Bank, N.A., as Administrative Agent, Citibank, N.A., as Syndication Agent, Barclays Bank PLC, The Bank of Nova Scotia and Wachovia Bank, National Association, as Co-Documentation Agents, and other lenders as named herein (Exhibit 10.1, Form 8-K filed May 18, 2005, File No. 1-8489, incorporated by reference).
	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).

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 3, 2005	/s/ Steven A. Rogers                        Steven A. Rogers Vice President and Controller (Principal Accounting Officer)