UNITED ~~SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ____________ FORM 10-Q ____________~~ 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 March 31, 2006

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

~~Commission~~SECURITIES EXCHANGE ~~File~~ACT ~~Number~~OF ~~1-3196~~1934

For the transition period from to

Commission File Number 001-03196

CONSOLIDATED NATURAL GAS COMPANY

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)

(Exact name of registrant as specified in its charter)

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.

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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. ~~(as~~See ~~defined~~definition byof “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act). ~~Yes No X~~

At Large accelerated ~~June 30, 2004, the latest practicable date for determination, 100 shares of common stock, without par value, of the registrant were outstanding.~~ filer ¨ Accelerated filer ¨ Non-accelerated filer x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

At March 31, 2006, 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, 2004 and 2003	3
	Consolidated Balance Sheets - June 30, 2004 and December 31, 2003	4
	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2004 and 2003	6
	Notes to Consolidated Financial Statements	7
Item 2	Management's Discussion and Analysis of Results of Operations	17
Item 4	Controls and Procedures	30
	PART II. Other Information
Item 1	Legal Proceedings	31
Item 5	Other Items	31
Item 6	Exhibits and Reports on Form 8-K	31

INDEX

		Page Number
PART I. Financial Information
Item 1.	Consolidated Financial Statements
	Consolidated Statements of Income - Three Months Ended March 31, 2006 and 2005	3
	Consolidated Balance Sheets - March 31, 2006 and December 31, 2005	4
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2006 and 2005	6
	Notes to Consolidated Financial Statements	7
Item 2.	Management's Discussion and Analysis of Results of Operations	22
Item 4.	Controls and Procedures	31
	PART II. Other Information
Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	32
Item 6.	Exhibits	34

PAGE 3

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

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

	Three Months Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
	(millions)
Operating Revenue
External customers	$1,011	$916	$2,781	$2,527
Affiliated customers	290	171	598	284
Total operating revenue	1,301	1,087	3,379	2,811
Operating Expenses
Purchased gas, net
External suppliers	371	235	1,285	899
Affiliated suppliers	129	170	279	295
Electric fuel and energy purchases
External suppliers	35	20	77	55
Affiliated suppliers	53	17	91	27
Liquids, pipeline capacity and other purchases	58	43	109	96
Other operations and maintenance
External	83	153	193	294
Affiliated	38	39	80	84
Depreciation, depletion and amortization	154	150	308	290
Other taxes	54	48	136	130
Total operating expenses	975	875	2,558	2,170
Income from operations	326	212	821	641
Other income (expense)	11	(9)	40	(8)
Interest and related charges:
Interest expense-junior subordinated notes payable to affiliated trust	4	-	8	-
Interest expense - other	37	36	75	71
Distributions-mandatorily redeemable trust preferred securities	-	4	-	8
Total interest and related charges	41	40	83	79
Income before income taxes	296	163	778	554
Income tax expense	114	60	285	199
Income before cumulative effect of a change in accounting principle	182	103	493	355
Cumulative effect of a change in accounting principle (net of income taxes of $3)	-	-	-	(5)
Net income	$ 182	$ 103	$ 493	$ 350

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

~~____________~~CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended March 31,
	2006	2005
	(millions)

Operating Revenue
External customers	$2,623	$2,115
Affiliated customers	202	261
Total operating revenue	2,825	2,376

Operating Expenses
Purchased gas
External suppliers	1,178	1,042
Affiliated suppliers	172	133
Electric fuel and energy purchases
External suppliers	31	27
Affiliated suppliers	34	45
Other energy-related commodity purchases	226	89
Other operations and maintenance
External suppliers	298	240
Affiliated suppliers	51	43
Depreciation, depletion and amortization	218	166
Other taxes	99	90
Total operating expenses	2,307	1,875

Income from operations	518	501

Other income	5	3

Interest and related charges
Interest expense	64	48
Interest expense - junior subordinated notes payable to affiliated trust	4	4
Total interest and related charges	68	52

Income before income taxes	455	452
Income tax expense	254	165

Net Income	$ 201	$ 287

________________

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

PAGE 4

CONSOLIDATED NATURAL GAS COMPANY ~~CONSOLIDATED BALANCE SHEETS (Unaudited)~~

	June 30, 2004	December 31, 2003(1)
	(millions)
ASSETS
Current Assets
Cash and cash equivalents	$ 29	$ 39
Customer accounts receivable (net of allowance of $30 in 2004 and $37 in 2003)	691	795
Other accounts receivable	51	45
Receivables due from affiliates	412	340
Inventories	150	238
Prepayments	35	56
Derivative assets	186	106
Other	272	296
Total current assets	1,826	1,915
Investments
Investment in affiliates	212	203
Other	83	79
Total investments	295	282
Property, Plant and Equipment
Property, plant and equipment	16,458	15,854
Accumulated depreciation, depletion and amortization	(5,932)	(5,674)
Net property, plant and equipment	10,526	10,180
Deferred Charges and Other Assets
Goodwill, net	623	626
Regulatory assets	341	328
Prepaid pension cost	928	872
Derivative assets	300	84
Other	210	210
Total deferred charges and other assets	2,402	2,120
Total assets	$15,049	$14,497

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2006	December 31, 2005⁽¹⁾
	(millions)
ASSETS

Current Assets
Cash and cash equivalents	$ 24	$ 44
Accounts receivable:
Customers (less allowance for doubtful accounts of $15 and $27)	1,343	1,502
Affiliates	223	214
Other	111	110
Inventories	69	366
Derivative assets	1,672	1,991
Deferred income taxes	310	510
Assets held for sale	1,154	2
Prepayments	78	122
Other	389	567
Total current assets	5,373	5,428

Investments	316	305

Property, Plant and Equipment
Property, plant and equipment	18,682	19,126
Accumulated depreciation, depletion and amortization	(6,589)	(6,780)
Total property, plant and equipment, net	12,093	12,346

Deferred Charges and Other Assets
Goodwill	623	623
Prepaid pension cost	1,112	1,086
Derivative assets	973	1,403
Regulatory assets	116	403
Other	315	308
Total deferred charges and other assets	3,139	3,823

Total assets	$20,921	$21,902

________________

(1)The Consolidated Balance Sheet at December 31, 2005 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)~~

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

	June 30, 2004	December 31, 2003(1)
				March 31, December 31, 2006 2005(1)
	~~(millions)~~	(millions)
LIABILITIES AND SHAREHOLDER'S EQUITY
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	~~$ 555~~	$ 734	~~$ 501~~		$	734
Short-term debt	-	339	~~151~~			187
Accounts payable, trade	630		655
Accounts payable		998				1,438
Payables to affiliates	~~122~~	112	~~118~~			151
Affiliated current borrowings	~~645~~	2,135	~~1,027~~			1,922
Accrued interest, payroll and taxes	~~241~~	255	~~214~~			250
Derivative liabilities	~~991~~	2,921	~~620~~			3,731
Other	468		278
Liabilities held for sale		443				--
Total current liabilities	3,652		3,564
Other		421				489
Long-Term Debt
Total current liabilities		8,358				8,902
Long-term debt	3,052		3,213
Long-Term Debt
Junior subordinated notes payable to affiliated trust	206		206
Long-term debt		2,704				2,708
Total long-term debt	3,258		3,419
Junior subordinated notes payable to affiliated trust		206				206
Deferred Credits and Other Liabilities
Total long-term debt		2,910				2,914
Deferred income taxes and investment tax credits	1,858		1,760
Deferred Credits and Other Liabilities
Asset retirement obligations	245		240
Deferred income taxes and investment tax credits		2,335				2,321
Derivative liabilities	~~1,057~~	1,942	~~669~~			2,706
Regulatory liabilities	~~216~~	129	~~212~~			147
Other	~~458~~	590	~~268~~			621
Total deferred credits and other liabilities	~~3,834~~	4,996	~~3,149~~			5,795
Total liabilities	~~10,744~~	16,264	~~10,132~~			17,611
Commitments and Contingencies (see Note 13)
Common Shareholder's Equity
Common Shareholder’s Equity
Common stock-no par value, 100 shares authorized and outstanding	1,816		1,816
Common stock—no par value, 100 shares authorized and outstanding		1,816				1,816
Other paid-in capital	~~2,478~~	3,273	~~2,478~~			3,273
Retained earnings	~~830~~	981	~~608~~			971
Accumulated other comprehensive loss	~~(819)~~	(1,413)	~~(537)~~			(1,769	)
Total common shareholder's equity	4,305		4,365
Total common shareholder’s equity		4,657				4,291
Total liabilities and shareholder's equity	$15,049		$14,497
Total liabilities and shareholder’s equity		$20,921			$	21,902

________________

(1)The Consolidated Balance Sheet at December 31, 2005 has been derived from the audited Consolidated

Financial Statements at that date.

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

PAGE 6

CONSOLIDATED NATURAL GAS COMPANY ~~CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)~~

	Six Months Ended June 30,
	2004	2003
	(millions)
Operating Activities
Net income	$ 493	$ 350
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	308	290
Deferred income taxes and investment tax credits, net	214	117
Valuation adjustment on CNG International assets	(18)	-
Cumulative effect of a change in accounting principle, net of income taxes	-	5
Changes in:
Accounts receivable	98	56
Affiliated receivables and payables	(68)	(134)
Inventories	88	(5)
Prepayments	21	51
Margin deposit assets and liabilities	14	(121)
Deferred purchased gas costs, net	1	(129)
Accounts payable, trade	(25)	(20)
Accrued interest, payroll and taxes	27	17
Other operating assets and liabilities	(62)	142
Net cash provided by operating activities	1,091	619
Investing Activities
Additions to gas and oil properties, including acquisitions	(543)	(475)
Proceeds from sales of gas and oil properties	413	-
Plant construction and other property additions	(132)	(197)
Other	47	(1)
Net cash used in investing activities	(215)	(673)
Financing Activities
Repayment of short-term debt, net	(151)	(380)
Issuance (repayment) of affiliated current borrowings, net	(382)	702
Repayment of long-term debt	(88)	-
Common stock dividend payments	(271)	(245)
Other	6	-
Net cash (used in) provided by financing activities	(886)	77
Increase (decrease) in cash and cash equivalents	(10)	23
Cash and cash equivalents at beginning of period	39	22
Cash and cash equivalents at end of period	$ 29	$ 45

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2006	2005
	(millions)

Operating Activities
Net income	$ 201	$ 287
Adjustments to reconcile net income to net cash provided by operating activities:
Net realized and unrealized derivative (gains)/losses	(258)	1
Depreciation, depletion and amortization	218	166
Deferred income taxes and investment tax credits, net	197	61
Charges related to pending sale of gas distribution subsidiaries	167	--
Other adjustments to net income	(44)	18
Changes in:
Accounts receivable	(81)	(257)
Affiliated accounts receivables and payable	(20)	35
Inventories	280	163
Purchased gas costs, net	94	74
Accounts payable	(380)	(130)
Accrued interest, payroll and taxes	38	151
Margin deposit assets and liabilities	(110)	(158)
Deferred revenues	(49)	(67)
Other operating assets and liabilities	188	112
Net cash provided by operating activities	441	456

Investing Activities
Additions to gas and oil properties, including acquisitions	(438)	(351)
Plant construction and other property additions	(86)	(67)
Acquisition of business, net of cash acquired	(91)	--
Proceeds from sales of gas and oil properties	--	86
Other	(16)	(5)
Net cash used in investing activities	(631)	(337)

Financing Activities
Short-term borrowings from affiliates, net	213	126
Issuance of short-term debt	152	--
Common dividend payments	(191)	(214)
Net cash provided by (used in) financing activities	174	(88)

Increase (decrease) in cash and cash equivalents	(16)	31
Cash and cash equivalents at beginning of period	44	19
Cash and cash equivalents at end of period⁽¹⁾	$ 28	$ 50

________________

⁽¹⁾2006 amount includes $4 million of cash classified as held for sale on the Consolidated Balance Sheet.

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

PAGE 7

CONSOLIDATED NATURAL GAS COMPANY ~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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~~Our ~~Company, through its~~ subsidiaries, ~~operates~~operate in all phases of the natural gas business, ~~explores~~explore for and ~~produces~~produce gas and oil and ~~provides~~provide a variety of energy marketing services. ~~Its~~Our 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~~ our nonregulated retail energy marketing businesses serve ~~approximately~~ 1.42 million residential and commercial gas and electric customer accounts in the Northeast, Mid-Atlantic and Midwest. We operate ~~The Company operates~~ an interstate gas transmission pipeline system and underground natural gas storage system in the ~~Midwest~~Northeast, ~~the~~Midwest and Mid-Atlantic states and ~~the Northeast and~~ a liquefied natural gas (LNG) import and storage facility in Maryland. ~~The Company's~~ Our producer services operations involve the aggregation of natural gas supply and related wholesale activities. ~~The~~Our ~~Company's~~ exploration and production operations are located in several major gas and oil producing basins in the United States, both onshore and offshore.

We ~~The~~ manage our ~~Company manages its~~ daily operations through three primary operating segments: ~~Energy~~Delivery, ~~Delivery~~ Energy and Exploration & Production (E&P). In addition, ~~the~~we ~~Company~~report ~~reports~~our ~~its~~ corporate and other functions as a segment. Assets remain wholly-owned by ~~the~~our ~~Company's~~ legal subsidiaries.

The " terms “Company",” is“we,” “our” and “us” are used throughout this report and, depending on the context of ~~its~~their use, may represent any of the following: the legal entity, Consolidated Natural Gas Company, one of Consolidated Natural Gas Company'’s consolidated subsidiaries or operating segments 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~~GAAP). These unaudited Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes in ~~the Company's~~ our Annual Report on Form 10-K for the year ended December 31, ~~2003 and the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004~~2005.

In ~~the~~ our opinion ~~of the Company's management~~, ~~the~~our accompanying unaudited Consolidated Financial Statements contain all adjustments, including normal recurring accruals, necessary to present fairly ~~the~~our ~~Company's~~ financial position as of ~~June~~March 3031, ~~2004~~2006, ~~its~~and our results of operations ~~for the three~~ and ~~six months ended June 30, 2004 and 2003, and its~~ cash flows for the ~~six~~three months ended ~~June~~March 3031, ~~2004~~2006 and ~~2003~~2005.

We ~~The Company makes~~ make certain estimates and assumptions in preparing ~~its~~our Consolidated Financial Statements in accordance with ~~generally accepted accounting principles~~GAAP. 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.

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

We ~~The Company reports~~ report certain contracts and instruments at fair value in accordance with ~~generally accepted accounting principles~~GAAP. Market pricing and indicative price information from external sources are used to measure fair value when available. In the absence of this information, ~~the~~we estimate ~~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~~our ~~Company's~~ Annual Report on Form 10-K for the year ended December 31, ~~2003~~2005 for a more detailed discussion of ~~the Company's~~ our estimation techniques.

PAGE 8

CONSOLIDATED NATURAL GAS COMPANY ~~NOTES TO CONSOLIDATED~~

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

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

Certain amounts in the ~~2003~~2005 Consolidated Financial Statements and Notes have been reclassified to conform to the ~~2004~~2006 presentation. ~~Note 3. Recently Adopted Accounting Standards~~

Note ~~2004 FIN~~ 3. Recently ~~46R~~Issued Accounting Standards

The Company adopted Financial Accounting Standards Board (FASB) Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, (FIN 46R) for its interests in variable interest entities (VIEs) that are not considered special purpose entities on March 31, 2004. FIN 46R addresses the identification and consolidation of VIEs, which are entities that are not controllable through voting interests or in which the VIEs' equity investors do not bear the residual economic risks and rewards. There was no impact on the Company's results of operations or financial position related to this adoption.EITF 04-13

We As enter into ~~described~~buy/sell ~~more~~and ~~fully~~related inagreements ~~Note~~primarily 3as a means to ~~the~~reposition ~~Consolidated~~our offshore ~~Financial~~Gulf ~~Statements~~of Mexico crude oil production to more liquid marketing locations onshore. We typically enter into either a single or a series of buy/sell transactions in ~~the~~which ~~Company's~~we ~~Annual~~sell ~~Report~~our oncrude ~~Form~~oil ~~10-K~~production ~~for~~at the ~~year~~offshore ~~ended~~field delivery ~~December~~point 31and buy similar quantities at Cushing, ~~2003~~Oklahoma for sale to third parties. We are able to enhance profitability by selling to a wide array of refiners and/or trading companies at Cushing, one of the ~~Company~~largest ~~adopted~~crude ~~FIN~~oil markets ~~46R~~in ~~for~~the ~~its~~world, ~~interests~~versus inrestricting ~~special~~sales ~~purpose~~to ~~entities~~a onlimited ~~December~~number ~~31,~~of ~~2003~~refinery purchasers in the Gulf of Mexico.

Under ~~2003~~ the primary guidance of Emerging Issues Task Force (EITF) Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent, we present the sales and purchases related to our crude oil buy/sell arrangements on a gross basis in our Consolidated Statements of Income. 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. Sales activity included in operating revenue was $232 million and $93 million for the three months ended March 31, 2006 and 2005, respectively. Purchase activity included in other energy-related commodity purchases expense was $224 million and $89 million for the three months ended March 31, 2006 and 2005, respectively.

In ~~SFAS~~ September 2005, the Financial Accounting Standards Board (FASB) ratified the EITF’s consensus on Issue No. ~~143~~04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, that will require buy/sell and related agreements with the same counterparty to be presented on a net basis in the Consolidated Statements of Income if they are entered into in contemplation of one another. This new guidance is required to be applied to all new arrangements entered into, and modifications or renewals of existing arrangements, beginning April 1, 2006. We adopted EITF 04-13 on April 1, 2006, and as a result a portion of our future activity related to buy/sell arrangements will be presented on a net basis in our Consolidated Statements of Income; however, there will be no impact on our results of operations or cash flows.

~~Effective~~PAGE 9 CONSOLIDATED NATURAL ~~January~~GAS 1, 2003, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, which provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Upon adoption, the Company recognized a $5 million after-tax loss as the cumulative effect of this change in accounting principle. COMPANY

NOTES ~~Note~~ TO ~~4. Classification~~CONSOLIDATED ofFINANCIAL ~~Oil and Gas Drilling Rights~~STATEMENTS

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

Note 5 4. ~~Recently~~ Acquisition ~~Issued Accounting Standards~~

In ~~EITF~~ February ~~03-1~~2006, we completed the acquisition of Pablo Energy LLC (Pablo) for approximately $92 million in cash. Pablo holds producing and other properties located in the Texas Panhandle area. The operations of Pablo are included in our E&P operating segment.

~~In March 2004, the FASB ratified the consensus reached by the Emerging Issues Task Force (EITF) on Issue No~~Note 5. Sale ~~03-1, The Meaning~~ of ~~Other-Than-Temporary~~Regulated ~~Impairment~~Gas ~~and~~Distribution Its Application to Certain Investments. EITF 03-1 provides guidance for evaluating whether certain investments in debt and equity securities are other-than-temporarily impaired and is effective for fiscal periods beginning after June 30, 2004. The Company does not expect a material impact on its Consolidated Financial Statements from the initial application of this new guidance.Subsidiaries

~~PAGE~~On March 1, 92006, we entered into an agreement with Equitable Resources, Inc., to sell two of our wholly-owned regulated gas distribution subsidiaries, The Peoples Natural Gas Company (Peoples) and Hope Gas, Inc. (Hope), for approximately $970 million plus adjustments to reflect capital expenditures and changes in working capital. Peoples and Hope serve approximately 500,000 customer accounts in Pennsylvania and West Virginia. The transaction is expected to close by the first quarter of 2007, subject to state regulatory approvals in Pennsylvania and West Virginia, as well as approval under the federal Hart-Scott-Rodino Act. The carrying amounts of the major classes of assets and liabilities classified as held for sale in our Consolidated Balance Sheet are as follows:

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

		March 31, 2006
ASSETS		(millions)

Current Assets
Cash		$ 4
Customer accounts receivable, net		243
Unrecovered gas costs		59
Other		32
Total current assets		338

Property, Plant and Equipment
Property, plant and equipment		1,078
Accumulated depreciation, depletion and amortization		(379)
Total property, plant and equipment, net		699

Deferred Charges and Other Assets
Regulatory assets		107
Other		8
Total deferred charges and other assets		115

Assets held for sale		$ 1,152

LIABILITIES

Current Liabilities
Accounts payable		$ 61
Provision for gas inventory replacement		52
Payables to affiliates		30
Accrued taxes		26
Deferred income taxes		24
Other		37
Total current liabilities		230

Deferred Credits and Other Liabilities
Asset retirement obligations		32
Deferred income taxes		160
Regulatory liabilities		10
Other		11
Total deferred credits and other liabilities		213

Liabilities held for sale		$ 443

Note 6. Operating Revenue

The Company's operating revenue consists of the following:

	Three Months Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
	(millions)
Operating Revenue
Regulated gas sales	$183	$180	$843	$731
Nonregulated electric sales	100	45	188	98
Nonregulated gas sales
External customers	148	171	511	533
Affiliated customers	271	161	564	260
Gas transportation and storage	165	147	437	414
Gas and oil production	317	298	613	595
Other	117	85	223	180
Total operating revenue	$1,301	$1,087	$3,379	$2,811

Note 7. Comprehensive Income

The following table presents total comprehensive income:

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

________________

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

PAGE 10

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

NOTES ~~Note~~ TO 8.CONSOLIDATED ~~Volumetric~~FINANCIAL ~~Production Payment (VPP) Transaction~~STATEMENTS

In May 2004, the Company received $413 million in cash for the sale of a fixed-term overriding royalty interest in certain of its proved natural gas reserves for the period May 2004 through April 2008. The sale reduced the Company's natural gas reserves by approximately 83 billion cubic feet (~~bcf~~Continued). While the Company is obligated under the agreement to deliver to the purchaser its portion of future natural gas production from the properties, it retains control of the properties and rights to future development drilling. If production from the properties is inadequate to deliver approximately 83 bcf of natural gas scheduled for delivery to the purchaser, the Company has no obligation to make up the shortfall. Cash proceeds received from this VPP transaction were recorded as deferred revenue. The Company will recognize revenue from the transaction as natural gas is produced and delivered to the purchaser. The Company also entered into a VPP transaction in 2003 for approximately 66 bcf for the period August 2003 through August 2007.

The In following ~~the~~table ~~second~~presents ~~quarter~~selected ofinformation ~~2004,~~regarding the ~~Company~~results ~~received~~of operations ~~cash proceeds~~ of ~~$48~~Peoples ~~million~~ and recognized a gain in other income of $8 million from the sale of a portion of the Australian pipeline business in which CNGI has held an investment. In the first quarter of 2004, the Company recognized an $18 million benefit from an adjustment to the carrying amount of this investment to reflect its then current estimate of fair value, less estimated costs to sell.Hope:

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

	Three Months Ended March 31,
	2006	2005
	(millions)
Operating Revenue	$357	$316

Income (loss) before income taxes	(128)	45

	Three Months Ended June 30,		Six Months Ended June 30,
	(millions)
	2004	2003	2004	2003
Portion of gains (losses) on hedging instruments determined to be ineffective and included in net income:
Fair value hedges	$ (1)	$(1)	-	$ 1
Cash flow hedges	4	(4)	$ 1	-
Net ineffectiveness	$ 3	$(5)	$ 1	$ 1
Portion of gains (losses) on hedging instruments attributable to changes in options' time value excluded from measurement of effectiveness and included in net income:
Fair value hedges	-	$ (1)	-	$ (1)
Cash flow hedges	$ 38	2	$ 74	6
Total change in options' time value	$ 38	$ 1	$ 74	$ 5

In March 2006, we recognized a $159 million ($94 million after-tax) charge, recorded in other operations and maintenance expense in our Consolidated Statements of Income, resulting from the write-off of certain regulatory assets related to the pending sale of Peoples and Hope, since the recovery of those assets is no longer probable. We also established $107 million of deferred tax liabilities on our Consolidated Balance Sheet in accordance with EITF Issue No. 93-17, Recognition of Deferred Tax Assets for a Parent Company's Excess Tax Basis in the Stock of a Subsidiary that is Accounted for as a Discontinued Operation. EITF 93-17 requires that the deferred tax impact of the excess of the financial reporting basis over the tax basis of a parent’s investment in a subsidiary be recognized when it is apparent that the temporary difference will reverse in the foreseeable future. We recorded an adjustment since the financial reporting basis of our investment in Peoples and Hope exceeds our tax basis. This temporary difference and related deferred taxes will reverse and will partially offset current tax expense recognized upon closing of the sale.

EITF Issue No. 03-13, Applying the Conditions of Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations, provides that the results of operations of a component of an entity that has been disposed of or is classified as held for sale shall be reported in discontinued operations if both of the following conditions are met: (a) the operations and cash flows of the component have been (or will be) eliminated from the ongoing operations of the entity as a result of the disposal transaction and (b) the entity will not have any significant continuing involvement in the operations of the component after the disposal transaction. While we do not expect to have significant continuing involvement with Peoples or Hope after their disposal, we do expect to have continuing cash flows related primarily to our sale to them of natural gas production from our exploration and production operations as well as natural gas transportation and storage services provided to them by our transmission operations. Due to these significant continuing cash flows, the results of Peoples and Hope have not been reported as discontinued operations in our Consolidated Statements of Income. We will continue to assess the level of our involvement and continuing cash flows with Peoples and Hope for one year after the date of sale and if circumstances change, we may be required to reclassify the results of Peoples and Hope as discontinued operations in our Consolidated Statements of Income.

PAGE 11

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

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

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

(Continued)

Note 6. Operating Revenue

Our operating revenue consists of the following:

	Three Months Ended March 31,
	2006	2005
	(millions)
Gas sales:
Regulated	$ 800	$ 778
Nonregulated:
External customers	618	415
Affiliated customers	193	252
Nonregulated electric sales	99	77
Other energy-related commodity sales	317	144
Gas transportation and storage	288	280
Gas and oil production	478	356
Other	32	74
Total operating revenue	$2,825	$2,376

Note 7. Income Taxes

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

	Three Months Ended March 31,
	2006	2005

U.S. statutory rate	35.0%	35.0%

Increases (decreases) resulting from:
Employee benefits	(0.5)	(1.3)
State taxes, net of federal benefit	3.4	2.2
Other, net	(0.1)	0.5
Subtotal	37.8	36.4
Changes in valuation allowances	(5.4)	--
Recognition of deferred taxes - stock of subsidiaries held for sale	23.5	--
Effective tax rate	55.9%	36.4%

Our effective tax rate for the three months ended March 31, 2006 reflects the recognition of $107 million of additional deferred income taxes related to the excess of our financial reporting basis over the tax basis in the stock of Peoples and Hope in accordance with EITF 93-17, as discussed in Note 5. In addition, in anticipation of the gain expected to result from the pending sale of Peoples and Hope, we reduced the valuation allowances on deferred tax assets, representing certain federal and state tax loss carryforwards.

PAGE 12

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

NOTES ~~Credit~~ TO ~~Facilities~~CONSOLIDATED FINANCIAL STATEMENTS

In June 2004, the Company entered into a $300 million letter of credit agreement that terminates in August 2004 and a $100 million letter of credit agreement that terminates in June 2007. These agreements support letter of credit issuances, providing collateral required on derivative financial contracts used by the Company in its risk management strategies for gas and oil production. At June 30, 2004, outstanding letters of credit under these agreements totaled $300 million.(Continued)

Note ~~In August 2003, the Company entered into a $1~~ 8.0 Comprehensive billion 364-day revolving credit facility that terminates in August 2004. This credit facility is being used to support the issuance of commercial paper and letters of credit to provide collateral required on derivative financial contracts used by the Company in its risk management strategies for gas and oil production. At June 30, 2004, outstanding letters of credit under this facility totaled $700 million. The Company expects to renew the $1.0 billion 364-day revolving credit facility prior to its maturity in August 2004.Income

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

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

	Three Months Ended March 31,
	2006	2005
	(millions)
Net income	$201	$287
Other comprehensive income (loss):
Net other comprehensive income (loss) associated with effective portion of changes in fair value of derivative cash flow hedges, net of taxes and amounts reclassified to earnings⁽¹⁾	356	(662)
Total comprehensive income (loss)	$557	$(375)

~~Long-Term Debt~~________________

In(1) Principally due ~~June~~to ~~2004,~~changes in the ~~Company~~fair ~~repaid~~value ~~$88~~of ~~million~~certain ofcommodity ~~its~~derivatives ~~9.25%~~resulting from fluctuations ~~senior~~in ~~notes~~commodity prices.

Note ~~Shelf~~ 9. Hedge ~~Registration~~Accounting Activities

AtWe are exposed ~~June~~to ~~30,~~the ~~2004,~~impact ~~the~~of ~~Company~~market ~~had~~fluctuations ~~$1.3~~in ~~billion~~the price of ~~available~~natural ~~capacity~~gas, natural ~~under~~gas aliquids, ~~shelf~~electricity ~~registration~~and ~~with~~oil and to the ~~SEC~~interest ~~that~~rate ~~would~~risks ~~permit~~of our business ~~the~~operations. ~~Company~~We use derivative instruments to ~~issue~~manage ~~debt~~our exposure to these risks and ~~trust~~designate ~~preferred~~certain ~~securities~~derivative toinstruments ~~meet~~as ~~future~~fair ~~capital~~value ~~requirements~~or cash flow hedges for accounting purposes as allowed by SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Selected information about our hedge accounting activities follows:

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

	Three Months Ended March 31,
	(millions)
	2006	2005
Portion of gains (losses) on hedging instruments determined to be ineffective and included in net income:
Fair value hedges	$ (1)	$ 2
Cash flow hedges	17	(4)
Net ineffectiveness	$ 16	$ (2)

Portion of gains on hedging instruments excluded from measurement of effectiveness and included in net income:
Fair value hedges	$ 1	$ --
Cash flow hedges	--	1
Total	$ 1	$ 1

PAGE 13

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

NOTES ~~Note~~ TO ~~13. Commitments~~CONSOLIDATED ~~and~~FINANCIAL ~~Contingencies~~STATEMENTS

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

As a result of June 30, 2004, the Company had issued $1.4 billion of guarantees, including: $1.0 billion to support commodity transactions of subsidiaries, $200 million for subsidiary debt and $184 million for guarantees supporting other agreements of subsidiaries. The Company had also purchased $49 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $1.3 billion. The Company enters into these arrangements to facilitate commercial transactions by its subsidiaries with third parties. While the majority of these guarantees do not have a ~~termination~~delay ~~date,~~in ~~the~~reaching ~~Company~~anticipated ~~may~~production ~~choose~~levels atin ~~any time to limit~~ the ~~applicability~~Gulf of ~~such guarantees to future transactions. To the extent that a liability subject to a guarantee has been incurred by a consolidated subsidiary~~ Mexico, ~~that~~we ~~liability~~discontinued ishedge ~~included~~accounting ~~in the Company's Consolidated Financial Statements. The Company is not required to recognize liabilities~~ for ~~guarantees~~certain oncash ~~behalf~~flow ofhedges ~~its subsidiaries~~ in ~~the~~March 2005 ~~Consolidated~~since ~~Financial Statements, unless~~ it ~~becomes~~became probable that the ~~Company~~forecasted ~~will~~sales ~~have~~of tooil ~~perform~~would ~~under~~not ~~the guarantee~~occur. The Nodiscontinuance ~~such liabilities have been recognized as~~ of ~~June~~hedge ~~30,~~accounting ~~2004.~~for ~~The~~these ~~Company~~contracts ~~believes~~resulted itin isa ~~unlikely~~$30 million ~~that~~($19 itmillion ~~would~~after-tax) bereclassification ~~required~~from AOCI to ~~perform~~earnings orin ~~otherwise incur any losses associated with guarantees of its subsidiaries' obligations~~March 2005.

The following table presents selected information related to cash ~~Note~~ flow hedges ~~14.~~included ~~Credit~~in ~~Risk~~accumulated other comprehensive income (loss) (AOCI) in our Consolidated Balance Sheet at March 31, 2006:

The Company sells natural gas and provides distribution services to residential, commercial and industrial customers and provides transmission services to utilities and other energy companies. In addition, the Company enters into contracts with various companies in the energy industry for purchases and sales of energy-related commodities, including natural gas and oil, in its hedging activities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. The Company's exposure to credit risk is concentrated primarily within its sales of gas and oil production and energy marketing activities as the Company transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. At June 30, 2004, gross credit exposure related to these transactions totaled $439 million, reflecting the unrealized gains for contracts carried at fair value plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral. After the application of collateral, the Company's credit exposure is reduced to $438 million. Of this amount, investment grade counterparties represent 51% and no single counterparty exceeded 5%. The credit exposure amounts exclude amounts receivable from affiliated companies. As of June 30, 2004 and December 31, 2003, the Company had margin deposit assets (reported in other current assets) of $46 million and $59 million, respectively. The Company had $1 million of margin deposit liabilities (reported in other current liabilities) as of June 30, 2004. The Company had no margin deposit liabilities as of December 31, 2003.

	AOCI After Tax	Portion Expected to be Reclassified to Earnings During the Next 12 Months After Tax	Maximum Term
	(millions)
Commodities:
Gas	$ (841)	$(480)	57 months
Oil	(570)	(339)	33 months
Other	(2)	(2)	7 months
Interest Rate	(1)	-	104 months
Total	$(1,414)	$(821)

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.

Note 10. Ceiling Test

We follow 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 11% of our 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 March 31, 2006.

Note 11. Variable Interest Entities

In accordance with FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, (FIN 46R), we consolidate a variable interest lessor entity through which we have financed and leased a power generation project. The Consolidated Balance Sheets as of March 31, 2006 and December 31, 2005 reflect net property, plant and equipment of $206 million and $207 million, respectively, and $234 million of debt related to this entity. The debt is nonrecourse to us and is secured by the entity’s property, plant and equipment.

PAGE 14

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ~~(Continued)~~

The Company engages in related party transactions primarily with other Dominion subsidiaries. The Company's accounts receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. The significant related party transactions are disclosed below.(Continued)

Note ~~Transactions~~ 12. Significant ~~with~~Financing ~~Other~~Transactions ~~Dominion Subsidiaries~~

~~The~~Joint Credit ~~Company~~Facilities transacts with other Dominion subsidiaries for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. The Company also enters into certain financial derivative commodity contracts with Dominion subsidiaries. These contracts, which are principally comprised of commodity swaps and options, are used by the Company to manage commodity price risks associated with the purchases and sales of natural gas. The Company designates the majority of these contracts as cash flow hedges for accounting purposes. The affiliated commodity transactions below include total net realized gains on affiliate commodity derivative transactions of $7 million and $20 million in the second quarter of 2004 and 2003, respectively, and $10 million and $25 million in the first six months of 2004 and 2003, respectively.

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

We use short-term debt, primarily commercial paper, to fund working capital requirements and as a bridge to long-term debt financing. The level of our borrowings may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, we utilize cash and letters of credit to fund collateral requirements under our commodities hedging program. Collateral requirements are impacted by commodity prices, hedging levels and the credit quality of our companies and their counterparties. In February 2006, we entered into a $3.0 billion five-year revolving credit facility with Dominion and Virginia Electric and Power Company (Virginia Power), a wholly-owned subsidiary of Dominion, that replaced our $2.5 billion five-year facility dated May 2005. The $3.0 billion credit facility is scheduled to terminate in February 2011. This credit facility is being used for working capital, as support for the combined commercial paper programs of Dominion, Virginia Power and us and for other general corporate purposes. This credit facility can also be used to support up to $1.5 billion of letters of credit.

At March ~~The~~ 31, ~~Company's~~2006, ~~Consolidated~~total ~~Balance~~outstanding ~~Sheets~~commercial ~~include~~paper ~~derivative~~supported ~~assets~~by ofthe ~~$26~~credit ~~million~~facility was ~~and~~ $501.4 ~~million with Dominion subsidiaries at June 30~~billion, ~~2004~~of ~~and~~which ~~December~~our ~~31,~~borrowings ~~2003,~~were ~~respectively, and derivative liabilities of~~ $49339 million. ~~and~~At ~~$48~~March ~~million with Dominion subsidiaries at June 30, 2004 and December~~ 31, ~~2003~~2006, total ~~respectively.~~outstanding ~~Unrealized~~letters ~~gains~~of orcredit ~~losses,~~supported ~~representing~~by the ~~effective~~credit ~~portion~~facility ofwere ~~the changes in fair value of those derivative contracts that had been designated as hedges~~$631 million, ~~are~~none ~~included in the balance~~ of ~~accumulated~~which ~~other~~were ~~comprehensive~~issued ~~loss~~on inour ~~the Consolidated Balance Sheets~~behalf.

At ~~Dominion Resources Services~~ March 31, ~~Inc.~~2006, acapacity ~~Dominion~~available ~~subsidiary,~~under ~~provides accounting, legal and certain administrative and technical services to~~ the ~~Company.~~credit ~~The~~facility ~~Company~~was ~~recognized expense of~~ $39 million in both the second quarter of 2004 and 2003, and $83 million and $86 million in the first six months of 2004 and 2003, respectively, in operations and maintenance expense related to these services1.0 billion.

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

In February 2006, we amended and restated our $1.75 billion five-year revolving credit facility, dated August 2005 with the facility limit reduced to $1.70 billion. Also in February 2006, we entered into a $1.05 billion 364-day credit facility, which is scheduled to terminate in February 2007. These credit facilities are being used to support our issuance of commercial paper and letters of credit to provide collateral required by counterparties on derivative financial contracts used in our risk management strategies for our gas and oil production. At March 31, 2006, outstanding letters of credit under these facilities totaled $1.1 billion.

In addition to the facilities above, we have also entered into several bilateral credit facilities in order to provide collateral required on derivative contracts used in our risk management strategies for gas and oil production operations. At March 31, 2006, we had the following letter of credit facilities:

Facility Limit	Outstanding Letters of Credit	Facility Capacity Remaining	Facility Inception Date	Facility Maturity Date
millions
$100	$100	$---	June 2004	June 2007
100	100	---	August 2004	August 2009
150⁽¹⁾	---	150	October 2004	April 2006
200⁽²⁾	---	200	December 2005	December 2010
$550	$200	$350

(1) We did not renew this facility prior to its maturity.

(2) This facility can also be used to support commercial paper borrowings.

Securities Law Reforms

In December 2005, the SEC adopted rules that modify the registration, communication and offering processes under the Securities Act of 1933. The rules streamline the shelf registration process to provide registrants with more timely access to capital. Under the new rules, we meet the definition of a seasoned issuer, and as such our filings remain subject to review by the SEC.

PAGE 15

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ~~(Continued)~~

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

	Pension Benefits		Other Postretirement Benefits
	2004	2003	2004	2003
Three Months Ended June 30,	(millions)
Service cost	$ 2	$ 2	$ 5	$ 3
Interest cost	7	8	7	5
Expected return on plan assets	(25)	(24)	(4)	(2)
Amortization of transition obligation	-	(1)	2	1
Amortization of net (gain) loss	-	(2)	2	2
Net periodic benefit cost (credit)	$(16)	$(17)	$12	$9
Company's net periodic benefit cost (credit)(1)	$(28)	$(33)	$17	$14
Six Months Ended June 30,
Service cost	$ 5	$ 4	$ 9	$ 6
Interest cost	15	15	13	11
Expected return on plan assets	(50)	(48)	(7)	(4)
Amortization of transition obligation	(1)	(2)	3	2
Amortization of net (gain) loss	-	(4)	5	4
Net periodic benefit cost (credit)	$(31)	$(35)	$23	$19
Company's net periodic benefit cost (credit)(1)	$(56)	$(66)	$32	$28

Note 13. 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 our Annual Report on Form 10-K for the year ended December 31, 2005, nor have any significant new matters arisen during the three months ended March 31, 2006.

~~(1)~~ Lease Commitment

During ~~Employer~~ the ~~Contributions~~three months ended March 31, 2006, we signed several contracts to lease onshore drilling rigs. The terms of the contracts range from two to three years. Our total minimum commitment under the agreements is approximately $194 million.

Guarantees, ~~The~~ Letters ~~Company made no contributions to its defined benefit pension plans or other postretirement benefit plans during the first six months~~ of ~~2004.~~Credit The Company expects to contribute at least $51 million to its other postretirement benefit plans during the remainder of 2004. Under its funding policies, the Company evaluates plan funding requirements annually, usually in the third quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and ~~other~~Surety ~~factors, the amount of additional contributions to be made in 2004 will be determined at that time.~~Bonds

In 2005, we, along with two other gas and oil exploration and production companies, entered into a four-year drilling contract related to a new, ultra-deepwater drilling rig that is expected to be delivered in mid-2008. The contract has a four-year primary term, plus four one-year extension options. Our minimum commitment under the agreement is for approximately $99 million over the four-year term; however, we are jointly and severally liable for up to $394 million to the contractor if the other parties fail to pay the contractor for their obligations under the primary term of the agreement, which we view as highly unlikely. We have not recognized any significant liabilities related to this guarantee arrangement.

We also enter into guarantee arrangements on behalf of our consolidated subsidiaries primarily to facilitate their commercial transactions with third parties. To the extent that a liability subject to a guarantee has been incurred by one of our consolidated subsidiaries, that liability is included in our Consolidated Financial Statements. We are not required to recognize liabilities for guarantees issued on behalf of our subsidiaries unless it becomes probable that we will have to perform under the guarantees. No such liabilities have been recognized as of March 31, 2006. We believe it is unlikely that we would be required to perform or otherwise incur any losses associated with guarantees of our subsidiaries’ obligations. At March 31, 2006, we had issued the following subsidiary guarantees:


	Stated Limit	Value⁽¹⁾
(millions)
Subsidiary debt⁽²⁾	$205	$205
Offshore drilling commitments⁽³⁾	---	493
Commodity transactions⁽⁴⁾	1,235	795
Miscellaneous	343	254
Total subsidiary obligations	$1,783	$1,747

(1)

Represents the estimated portion of the guarantees’ stated limit that is utilized as of March 31, 2006 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by our subsidiaries, the value includes the recorded amount.

(2)	Guarantees of debt of Dominion Oklahoma Texas Exploration and Production Inc. (DOTEPI). In the event of default by this subsidiary, we would be obligated to repay such amounts.

(3)	There is no stated limit for this guarantee.

(4)

Guarantees of contract payments for certain subsidiaries involved in natural gas and oil production, natural gas delivery and energy marketing activities. These guarantees were provided to counterparties in order to facilitate physical and financial transactions in gas, pipeline capacity, transportation, oil, electricity and related commodities and services. If any of these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, we would be obligated to satisfy such obligation. We and our subsidiaries receive similar guarantees as collateral for credit extended to others. The value provided includes certain guarantees that do not have stated limits.

We also purchased $44 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $1.3 billion. We enter into these arrangements to facilitate commercial transactions by our subsidiaries with third parties.

PAGE 16

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ~~(Continued)~~

~~Note 17. Operating Segments~~(Continued)

Note ~~The Company is organized primarily on the basis of products and services sold in the United States~~ 14. Credit ~~The~~Risk ~~Company manages its operations based on three primary operating segments:~~

We ~~Energy~~ sell natural ~~includes~~gas ~~the~~and ~~Company's~~provide ~~gas~~distribution services to residential, commercial and industrial customers and provide transmission ~~pipeline~~services to utilities and ~~storage~~other energy ~~system~~companies. In addition, ~~certain~~we ~~gas~~enter ~~production~~into ~~operations,~~contracts awith ~~liquefied~~various companies in the energy industry for purchases and sales of energy-related commodities, including natural gas ~~import~~and oil. Except for gas and ~~storage~~oil ~~facility~~exploration and ~~producer~~production business ~~services~~activities, ~~operations~~these ~~that~~transactions ~~include~~principally ~~aggregation~~occur ofin ~~gas~~the ~~supply~~Northeast, Midwest and ~~related~~Mid-Atlantic ~~wholesale~~regions ~~activities~~of the United States. We do not believe that this geographic concentration contributes significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers.

Our ~~Delivery~~ exposure to credit risk is concentrated primarily within our sales of gas and oil production and energy marketing, including our hedging activities. At March 31, 2006, gross credit exposure related to these transactions totaled $618 million, reflecting the unrealized gains for contracts carried at fair value plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral. After the application of collateral, our credit exposure is reduced to $580 million. Of this amount, investment grade counterparties represented 72% and no single counterparty exceeded 8%.

Note ~~Exploration & Production includes the Company's onshore and offshore gas and oil exploration, development and production operations~~ 15. Related ~~These~~Party ~~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.~~Transactions

We ~~Corporate~~ engage in ~~and~~related ~~Other~~party ~~includes~~transactions ~~the~~primarily ~~Company's~~with ~~corporate~~affiliates ~~and~~(Dominion ~~other functions, including the activities of CNGI and other minor~~ subsidiaries). Our ~~The~~accounts ~~contribution~~receivable toand ~~net~~payable ~~income~~balances bywith ~~the~~affiliates ~~Company's~~are ~~primary~~settled ~~operating~~based on ~~segments~~contractual isterms ~~determined~~or ~~based~~ on a ~~measure~~monthly ofbasis, ~~profit~~depending ~~that~~on ~~executive~~the ~~management~~nature ~~believes~~of ~~represents~~ the underlying ~~segments' core earnings~~transactions. AsWe ~~a result, certain specific items attributable to those segments~~ are ~~not~~ included in ~~profit~~Dominion’s ~~measures~~consolidated ~~evaluated~~federal income bytax ~~executive~~return ~~management~~and participate in ~~assessing~~certain ~~the~~Dominion ~~segment's~~benefit ~~performance or allocating resources among the segments~~plans. ~~These~~The significant ~~specific~~related ~~items~~party transactions are ~~instead~~disclosed ~~reported in the Corporate and Other segment~~below.

	Energy	Delivery	Exploration & Production	Corporate and Other	Eliminations	Consolidated Total
	(millions)
Three Months ended June 30, 2004
Operating revenue - external customers	$463	$391	$430	$ 17	$ -	$1,301
Operating revenue - intersegment	52	15	34	-	(101)	-
Net income (loss)	38	28	144	(28)	-	182
Three Months ended June 30, 2003
Operating revenue - external customers	$378	$326	$371	$12	$ -	$1,087
Operating revenue - intersegment	50	12	30	-	(92)	-
Net income (loss)	40	11	75	(23)	-	103
Six Months Ended June 30, 2004
Operating revenue - external customers	$1,029	$1,521	$802	$ 27	$ -	$3,379
Operating revenue - intersegment	111	34	68	-	(213)	-
Net income (loss)	121	127	253	(8)	-	493
Six Months Ended June 30, 2003
Operating revenue - external customers	$797	$1,235	$755	$24	$ -	$2,811
Operating revenue - intersegment	119	25	67	-	(211)	-
Net income (loss)	121	103	159	(33)	-	350

Transactions with Affiliates

We transact with affiliates for certain quantities of natural gas, electricity and other commodities at market prices in the ordinary course of business. We also enter into certain derivative commodity contracts with affiliates. We use these contracts, which are principally comprised of commodity swaps and options, to manage commodity price risks primarily associated with the purchases and sales of natural gas. We designate the majority of these contracts as cash flow hedges for accounting purposes.

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

	Three Months Ended March 31,
	2006	2005
	(millions)
Sales of natural gas to affiliates	$193	$252
Gas transportation and storage services provided to affiliates	5	6
Sales of electricity to affiliates	4	3
Purchases of natural gas from affiliates	172	133
Purchases of electric fuel and energy from affiliates	34	45

At March 31, 2006 and December 31, 2005, our Consolidated Balance Sheets include derivative assets with affiliates of $261 million and $431 million, respectively, and derivative liabilities with affiliates of $76 million and $120 million, respectively. Unrealized gains or losses, representing the effective portion of the changes in fair value of those derivative contracts that have been designated as cash flow hedges, are included in AOCI on the Consolidated Balance Sheets.

PAGE 17

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

NOTES ~~The~~ TO ~~MD&A~~CONSOLIDATED ~~consists~~FINANCIAL ~~of the following information:~~ STATEMENTS

~~Forward-Looking Statements~~ (Continued)

~~Accounting~~Dominion Resources ~~Matters~~Services, Inc. (Dominion Services) provides certain administrative and technical services to us, which totaled $49 million and $45 million in the three months ended March 31, 2006 and 2005, respectively. We provide certain services to other affiliates, including technical services to other Dominion subsidiaries, which totaled $3 million and $2 million in the three months ended March 31, 2006 and 2005, respectively.

~~Results~~Transactions with ofDominion ~~Operations~~

~~Segment~~We have borrowed ~~Results~~funds from Dominion under short-term borrowing arrangements. At March 31, 2006 and December 31, 2005, our outstanding borrowings, net of ~~Operations~~repayments, under the Dominion money pool totaled $2.1 billion and $1.9 billion, respectively. The short-term demand note borrowings were $1 million at March 31, 2006. Net interest charges incurred by us related to these total borrowings were $26 million and $8 million in the three months ended March 31, 2006 and 2005, respectively.

~~Credit~~Note 16. Employee ~~Risk~~Benefit Plans

~~Risk~~The following ~~Factors~~table illustrates the components of the provision for net periodic benefit cost for our pension and ~~Cautionary~~other ~~Statements~~postretirement ~~That~~benefit ~~May~~plans ~~Affect~~for employees ~~Future~~represented ~~Results~~by collective bargaining units:

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.

	Pension Benefits		Other Postretirement Benefits
Three Months Ended March 31,	2006	2005	2006	2005
	(millions)
Service cost	$ 3	$ 3	$ 4	$ 4
Interest cost	8	8	7	6
Expected return on plan assets	(26)	(26)	(5)	(4)
Curtailment loss⁽¹⁾	-	-	3	-
Amortization of transition obligation	-	-	1	1
Amortization of prior service credit	-	-	(1)	-
Amortization of net loss	-	-	3	1
Net periodic benefit cost (credit)	$(15)	$(15)	$12	$ 8

Company’s net periodic benefit cost (credit)⁽²⁾	$(27)	$(25)	$19	$12

~~The~~(1) ~~Company~~Relates ~~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~~pending ~~statements~~sale ~~themselves.~~of ~~Additionally,~~Peoples ~~other~~and ~~risks~~Hope ~~that~~discussed ~~may cause actual results to differ from predicted results are set forth~~ in ~~Risk~~Note ~~Factors and Cautionary Statements That May Affect Future Results~~5.

~~The~~(2) ~~Company~~Amounts ~~bases~~represent ~~its~~all ~~forward-looking~~benefit ~~statements~~plans onin ~~management's~~which ~~beliefs~~we ~~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~~participate, ~~beliefs,~~including ~~expectations~~benefit ~~and~~plans ~~projections~~covering ~~about~~multiple ~~future~~Dominion ~~events may, and often do, materially differ from actual results~~subsidiaries. ~~The Company undertakes no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.~~

Employer ~~Critical Accounting Policies and Estimates~~ Contributions

AsWe made no ofcontributions ~~June~~to ~~30,~~our ~~2004,~~defined ~~there~~benefit ~~have~~pension ~~been~~plans noor ~~significant~~other ~~changes~~postretirement benefit ~~with~~plans ~~regard~~during the first quarter of 2006. We expect to ~~critical~~contribute ~~accounting~~at least $35 ~~policies~~million ~~and~~to ~~estimates~~our asother ~~disclosed~~postretirement inbenefit ~~MD&A~~plans induring the ~~Company's~~remainder of 2006. ~~Annual~~Under ~~Report~~our onfunding ~~Form~~policies, ~~10-K~~we ~~for~~evaluate ~~the~~pension and ~~year~~other ~~ended~~postretirement ~~December~~benefit 31plan funding requirements annually, ~~2003.~~usually ~~The~~in ~~policies~~the ~~disclosed~~second ~~included~~half of the ~~accounting~~year ~~for:~~after receiving ~~derivative~~updated ~~contracts~~plan atinformation ~~fair~~from ~~value;~~our ~~goodwill~~actuary. Based on the funded status of each plan and ~~long-lived~~other ~~asset~~factors, ~~impairment~~the ~~testing;~~amount ~~employee~~of ~~benefit~~additional ~~plans;~~contributions ~~regulated~~to ~~operations;~~be made ~~and~~in ~~gas~~2006 ~~and~~will ~~oil~~be ~~operations~~determined at that time.

PAGE 18

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

NOTES ~~FIN~~ TO ~~46R~~CONSOLIDATED FINANCIAL STATEMENTS

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

Note ~~Presented~~ 17. Condensed ~~below~~Consolidating ~~is a summary of contributions by the Company's operating segments to its net income:~~Financial Information

	Three Months Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
	(millions)
Energy	$ 38	$ 40	$ 121	$ 121
Delivery	28	11	127	103
Exploration & Production	144	75	253	159
Primary operating segments	210	126	501	383
Corporate and Other	(28)	(23)	(8)	(33)
Consolidated net income	$182	$103	$493	$350

We have fully and unconditionally guaranteed $200 million of senior notes issued by our wholly-owned subsidiary, DOTEPI. The senior notes mature in December 2007. In the event of a default by this subsidiary, we would be obligated to repay such amounts. Condensed consolidating financial information for the Company, DOTEPI and our other subsidiaries are presented below:

Condensed ~~Overview~~ Consolidating Statement of Income Information

Three Months Ended June 30, 2004 vs. 2003

Three Months Ended March 31, 2006	CNG (Parent Company)	DOTEPI	Other Subsidiaries	Adjustments & Eliminations	Consolidated
	(millions)

Operating revenue	$ --	$181	$2,815	$(171)	$2,825
Operating expense	1	136	2,327	(157)	2,307
Income from operations	(1)	45	488	(14)	518
Other income	60	--	5	(60)	5
Interest and related charges	53	14	62	(61)	68
Income before income taxes	6	31	431	(13)	455
Income tax expense	109	16	135	(6)	254
Equity in earnings of subsidiaries	304	--	--	(304)	--
Net income	$201	$ 15	$ 296	$(311)	$ 201

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

Three Months Ended March 31, 2005	CNG (Parent Company)	DOTEPI	Other Subsidiaries	Adjustments & Eliminations	Consolidated
	(millions)

Operating revenue	$ --	$176	$2,334	$(134)	$2,376
Operating expense	--	102	1,905	(132)	1,875
Income from operations	--	74	429	(2)	501
Other income	49	--	3	(49)	3
Interest and related charges	52	15	35	(50)	52
Income (loss) before income taxes	(3)	59	397	(1)	452
Income tax expense (benefit)	(2)	20	148	(1)	165
Equity in earnings of subsidiaries	288	--	--	(288)	--
Net income	$287	$ 39	$ 249	$(288)	$ 287

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

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

Six Months Ended June 30, 2004 vs. 2003

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

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

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

PAGE 19

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

NOTES ~~Analysis~~ TO ofCONSOLIDATED ~~Consolidated~~FINANCIAL ~~Operations~~ STATEMENTS

	Three Months Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
	(millions)
Operating Revenue
Regulated gas sales	$ 183	$ 180	$ 843	$ 731
Nonregulated electric sales	100	45	188	98
Nonregulated gas sales	419	332	1,075	793
Gas transportation and storage	165	147	437	414
Gas and oil production	317	298	613	595
Other	117	85	223	180
Operating Expenses
Purchased gas, net	500	405	1,564	1,194
Electric fuel and energy purchases	88	37	168	82
Liquids, pipeline capacity and other purchases	58	43	109	96
Other operations and maintenance	121	192	273	378
Depreciation, depletion and amortization	154	150	308	290
Other taxes	54	48	136	130
Other income (expense)	11	(9)	40	(8)
Interest and related charges	41	40	83	79
Income tax expense	114	60	285	199
Cumulative effect of changes in accounting principle (net of income taxes)	-	-	-	(5)

(Continued)

AnCondensed Consolidating ~~analysis~~Balance ofSheet ~~the Company's results of operations for the three and six months ended June 30, 2004, as compared to the same periods of 2003 follows.~~Information

Three Months Ended June 30, 2004 vs. 2003

At March 31, 2006	CNG (Parent Company)	DOTEPI	Other Subsidiaries	Adjustments & Eliminations	Consolidated
	(millions)
Assets
Current assets	$2,229	$ 419	$5,581	$(2,856)	$5,373
Investment in affiliates	4,166	--	156	(4,104)	218
Loan to affiliates	2,188	--	--	(2,188)	--
Property, plant and equipment, net	--	4,335	8,556	(798)	12,093
Deferred charges and other assets	277	561	2,908	(509)	3,237
Total assets	$8,860	$5,315	$17,201	$ (10,455)	$20,921

Liabilities & Shareholder’s Equity
Current liabilities	$ 1,333	$2,600	$8,955	$ (4,530)	$8,358
Long-term debt	2,506	198	--	--	2,704
Notes payable to affiliates	206	--	1,099	(1,099)	206
Deferred credits and other liabilities	158	1,214	4,290	(666)	4,996
Common shareholder’s equity	4,657	1,303	2,857	(4,160)	4,657
Total liabilities and shareholder’s equity	$8,860	$5,315	$17,201	$(10,455)	$20,921

Operating Revenue

At December 31, 2005	CNG (Parent Company)	DOTEPI	Other Subsidiaries	Adjustments & Eliminations	Consolidated
	(millions)
Assets
Current assets	$2,019	$ 539	$6,529	$(3,659)	$5,428
Investment in affiliates	3,697	--	147	(3,634)	210
Loan to affiliates	2,188	--	--	(2,188)	--
Property, plant and equipment, net	--	4,079	8,370	(103)	12,346
Deferred charges and other assets	373	555	3,621	(631)	3,918
Total assets	$8,277	$5,173	$18,667	$(10,215)	$21,902

Liabilities & Shareholder’s Equity
Current liabilities	$ 1,026	$2,646	$9,976	$(4,746)	$8,902
Long-term debt	2,508	200	--	--	2,708
Notes payable to affiliates	206	--	1,099	(1,099)	206
Deferred credits and other liabilities	246	1,231	5,004	(686)	5,795
Common shareholder’s equity	4,291	1,096	2,588	(3,684)	4,291
Total liabilities and shareholder’s equity	$8,277	$5,173	$18,667	$(10,215)	$21,902

Nonregulated electric sales revenue

PAGE 20

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

NOTES ~~Nonregulated~~ TO ~~gas~~CONSOLIDATED ~~sales~~FINANCIAL ~~revenue increased 26% to $419 million primarily reflecting:~~STATEMENTS

~~A $65 million increase in revenue from producer services operations, driven by higher prices~~ (~~$19 million~~Continued) and higher volumes ($46 million). This increase includes higher gas sales to another Dominion subsidiary, as part of Dominion's enterprise-wide price risk management. See Note 15 to the Consolidated Financial Statements;

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

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

Three Months Ended March 31, 2006	CNG (Parent Company)	DOTEPI	Other Subsidiaries	Adjustments & Eliminations	Consolidated
	(millions)
Net cash provided by operating activities	$204	$208	$220	$(191)	$441
Net cash used in investing activities	(165)	(297)	(432)	263	(631)
Net cash provided by (used in) financing activities	(40)	87	199	(72)	174

Gas transportation and storage revenue

Three Months Ended March 31, 2005	CNG (Parent Company)	DOTEPI	Other Subsidiaries	Adjustments & Eliminations	Consolidated
	(millions)
Net cash provided by operating activities	$236	$50	$378	$(208)	$456
Net cash used in investing activities	(22)	(138)	(185)	8	(337)
Net cash provided by (used in) financing activities	(214)	84	(158)	200	(88)

Note ~~Gas~~ 18. Operating ~~and oil production revenue increased 6% to $317 million primarily reflecting:~~Segments

AOur Company ~~$51~~is ~~million~~organized ~~increase~~primarily inon ~~revenue~~the ~~recognized~~basis ~~related~~of toproducts ~~deliveries~~and ~~under~~services ~~VPP~~sold ~~transactions;~~in the United ~~partially~~States. ~~offset~~We bymanage our operations through the following segments:

ADelivery includes our ~~$32~~regulated ~~million~~gas ~~decrease~~distribution inand ~~revenue~~customer ~~from~~service ~~gas~~businesses ~~production~~which are subject to cost-of-service rate regulation and accordingly, ~~primarily~~apply ~~reflecting~~SFAS No. 71, Accounting for the ~~sale~~Effects of ~~mineral~~Certain ~~rights~~Types ~~under~~of Regulation. It ~~the~~also includes ~~VPP~~our ~~agreements~~nonregulated retail energy marketing operations.

Energy ~~Other~~ includes our ~~revenue~~tariff-based natural gas transmission pipeline and underground natural gas storage businesses and an LNG facility which are subject to cost-of-service rate regulation and accordingly, apply SFAS No. 71. It also includes certain natural gas production operations and producer services, which consist of aggregation of gas supply and related wholesale activities.

AE&P includes our ~~$16~~gas ~~million~~and ~~increase~~oil exploration, development and production operations. Operations are located in ~~sales~~several ofmajor ~~purchased~~producing ~~oil~~basins byin ~~exploration~~the ~~and~~lower ~~production~~48 ~~operations~~states, ~~reflecting~~including the ~~higher~~outer ~~prices;~~continental shelf and deepwater areas of the Gulf of Mexico.

AnCorporate includes our corporate functions, including the activities of CNG International (CNGI), our power generating facility and other minor subsidiaries. In addition, the contribution to net income by our primary operating segments is determined based on a measure of profit that executive management believes represents our 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 and are instead reported in the Corporate segment. In the three months ended March 31, 2006, we reported net expenses of $11106 million ~~increase~~in the Corporate segment attributable to our operating segments. The net expenses in 2006 ~~sales~~primarily relate to a $159 million ($94 million after-tax) charge resulting from the write-off of ~~extracted~~certain ~~products,~~regulatory ~~reflecting~~assets ~~higher~~related ~~volumes;~~to the pending sale of Peoples and Hope, attributable to the Delivery segment.

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

Operating Expenses and Other Items

Purchased gas, net expense

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

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

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

Electric fuel and energy purchases expense

Liquids, pipeline capacity and other purchases expense

PAGE 21

CONSOLIDATED NATURAL GAS COMPANY

NOTES ~~ITEM~~ TO 2.CONSOLIDATED ~~MANAGEMENT'S~~FINANCIAL ~~DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS (Continued)~~STATEMENTS

~~Other operations and maintenance expense~~(Continued)

AIntersegment sales ~~$49~~and ~~million~~transfers ~~benefit~~are ~~primarily~~based ~~due~~on tounderlying ~~favorable~~contractual ~~changes~~arrangements ~~in the fair value of certain oil options. As provided for in SFAS No. 133, Accounting for Derivative Instruments~~ and agreements Hedging Activities, the Company excludes changes in options' time value from its calculation of hedge effectiveness. Such amounts, as well as changes in the fair value of options not designated as hedges, are reported in other operations and ~~maintenance~~may ~~expenses.~~result ~~During the period, the Company effectively settled certain options not designated as hedges by entering into offsetting option positions that had the effect of preserving approximately $42 million~~ in ~~mark-to-market~~intersegment ~~gains.~~profit ~~Future~~or ~~gains and losses on options will depend upon the relationship between an option's cost and future commodity prices;~~loss.

AThe following ~~$22~~table ~~million~~presents ~~asset~~segment ~~impairment~~information ~~charge~~pertaining ~~recognized in the second quarter of 2003 related~~ to ~~the Company's generation facility in Kauai, Hawaii that was sold in December 2003. No comparable charge was recognized during 2004; and~~our operations:

A $5 million decrease in bad debt expense.

	Delivery	Energy	E&P	Corporate	Eliminations	Consolidated Total
	(millions)
Three Months ended March 31, 2006
Operating revenue:
External customers	$1,385	$428	$810	$ —	$ —	$2,623
Affiliated customers	—	195	3	4	—	202
Intersegment	1	90	53	—	(144)	—
Total operating revenue	1,386	713	866	4	(144)	2,825
Net income (loss)	85	88	213	(185)	—	201

Three Months ended March 31, 2005
Operating revenue:
External customers	$1,234	$315	$566	$ —	$ —	$2,115
Affiliated customers	--	248	9	4	—	261
Intersegment	16	60	34	—	(110)	—
Total operating revenue	1,250	623	609	4	(110)	2,376
Net income (loss)	104	80	104	(1)	—	287

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

Other income

Income taxes

Six Months Ended June 30, 2004 vs. 2003

Operating Revenue

Nonregulated electric sales revenue

Nonregulated gas sales revenue

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

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

Gas transportation and storage

PAGE 22

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

ITEM ~~Gas~~ 2. ~~and~~MANAGEMENT'S ~~oil~~DISCUSSION ~~production~~AND ~~revenue~~ANALYSIS ~~increased~~OF ~~3% to $613 million primarily reflecting:~~

AnRESULTS OF ~~$80 million increase in revenue recognized related to deliveries under VPP transactions; partially offset by~~OPERATIONS

Management’s Discussion and Analysis of Results of Operations (MD&A) ~~$59~~discusses ~~million~~the results ~~decrease~~of operations and general financial condition of Consolidated Natural Gas Company. MD&A should be read in ~~revenue~~conjunction ~~from~~with ~~gas~~the ~~production~~Consolidated Financial Statements. The terms “Company,” ~~primarily~~“we,” ~~reflecting~~“our” and “us” are used throughout MD&A and, depending on the ~~sale~~context of ~~mineral~~their ~~rights~~use, ~~under~~may represent any of the ~~VPP~~following: ~~agreements~~the legal entity, Consolidated Natural Gas Company, one of Consolidated Natural Gas Company’s consolidated subsidiaries or operating segments or the entirety of Consolidated Natural Gas Company and its consolidated subsidiaries. We are a wholly-owned subsidiary of Dominion.

Contents ~~Other~~ of ~~revenue~~MD&A

AThe reader ~~$15~~will ~~million~~find ~~increase~~the infollowing ~~sales~~information ofin ~~purchased~~this ~~oil~~MD&A: ~~by exploration and production operations, reflecting higher prices;~~

A· ~~$17~~Forward-Looking ~~million increase in sales of extracted products, reflecting higher volumes; and~~Statements

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

~~Operating~~· ~~Expenses~~Results ~~and~~of ~~Other Items~~ Operations

~~Purchased~~· ~~gas,~~Segment ~~net~~Results ~~expense~~of Operations

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

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

AnForward-Looking Statements ~~$88 million increase associated with regulated gas sales discussed above in Regulated gas sales revenue.~~

~~The~~This report ~~increase~~contains instatements ~~purchased~~concerning ~~gas~~our ~~expense~~expectations, ~~reflects~~plans, ~~gas~~objectives, future ~~purchases~~financial ~~from~~performance ~~another~~and ~~Dominion~~other ~~subsidiary~~statements that are not historical facts. These ~~See~~statements ~~Note~~are 15“forward-looking tostatements” within the ~~Consolidated~~meaning ~~Financial~~of ~~Statements~~the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by such words as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may” or other similar words.

We ~~Electric~~ make forward-looking ~~fuel~~statements with full knowledge that risks and ~~energy~~uncertainties exist ~~purchases~~that ~~expense~~may cause actual results to differ materially from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other factors may cause actual results to differ materially from those indicated in any forward-looking statement. These factors include, but are not limited to:

~~Liquids,~~· ~~pipeline~~Unusual ~~capacity~~weather conditions and ~~other~~their ~~purchases~~effect ~~expense~~on energy sales to customers and energy commodity prices;

~~Other~~· ~~operations~~Extreme ~~and~~weather ~~maintenance~~events, ~~expense~~including ~~decreased~~hurricanes ~~28%~~and towinter ~~$273~~storms, ~~million~~that can cause outages, ~~primarily~~production ~~reflecting~~delays ~~the~~and ~~following:~~property damage to our facilities;

An· ~~$83~~State ~~million~~and ~~benefit~~federal ~~primarily~~legislative ~~due~~and toregulatory ~~favorable~~developments, including deregulation and changes in ~~the~~environmental ~~fair~~and ~~value~~other oflaws ~~certain~~and ~~oil~~regulations ~~options~~to aswhich ~~discussed~~we ~~previously;~~are subject;

A· ~~$22~~Cost ~~million~~of ~~asset~~environmental ~~impairment charge recognized in 2003 related to the Company's generation facility in Kauai, Hawaii that was sold in December 2003. No comparable charge was recognized during 2004~~compliance;

A· $9Fluctuations ~~million~~in ~~decrease~~energy-related incommodity ~~bad~~prices ~~debt~~and ~~expense;~~the effect these could have on our earnings, liquidity position and the underlying value of our assets;

A· $6Counterparty ~~million~~credit ~~charge recognized in 2003 related to severance costs for workforce reductions. No comparable charge was recognized during 2004.~~risk;

~~These~~· ~~decreases~~Capital ~~were~~market ~~partially~~conditions, ~~offset~~including byprice ~~lower~~risk ~~net~~due ~~pension~~to ~~credits~~marketable ~~and~~securities ~~higher~~held ~~OPEB~~as ~~costs~~investments ~~($15~~in ~~million).~~benefit plan trusts;

~~Depreciation,~~· ~~depletion~~Fluctuations ~~and~~in ~~amortization~~interest ~~expense~~rates;

~~Other~~· ~~income~~Change in rating agency requirements or credit ratings and the effect on availability and cost of capital;

~~Cumulative~~· ~~effect~~Changes ofin afinancial ~~change~~or inregulatory accounting ~~principle~~principles or policies imposed by governing bodies;

Employee workforce factors including collective bargaining agreements and labor negotiations with union employees;

The risks of operating businesses in regulated industries that are subject to changing regulatory structures;

Changes in our ability to recover investments made under traditional regulation through rates;

Receipt of approvals for and timing of closing dates for acquisitions and divestitures;

Realization of expected business interruption insurance proceeds and decreased availability of business interruption insurance on commercially reasonable terms; and

Political and economic conditions, including the threat of domestic terrorism, inflation and deflation.

PAGE 23

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

~~Segment~~ITEM 2. ~~Results~~MANAGEMENT'S ofDISCUSSION ~~Operations~~AND ANALYSIS OF

RESULTS ~~Energy~~ OF ~~Segment~~OPERATIONS

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

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

Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors in this report and in our Annual Report on Form 10-K for the year ended December 31, 2005.

~~__________________~~Our forward-looking statements are based on our beliefs and assumptions using information available at the time the statements are made. We caution the reader not to place undue reliance on our forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results. We undertake no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.

	Three Months Ended June 30,	Six Months Ended June 30,
	2004 vs. 2003 Increase (Decrease)	2004 vs. 2003 Increase (Decrease)
	(millions)
Gas prices	$(1)	$5
Cove Point LNG operations	2	5
Operations and maintenance expense	(6)	(9)
Other	3	(1)
Change in net income contribution	$(2)	$ -

Accounting Matters

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

~~Lower~~As of March ~~gas~~31, ~~prices~~2006, inthere ~~the~~have ~~second~~been ~~quarter~~no significant changes with regard to critical accounting policies and ~~higher~~estimates ~~gas~~as ~~prices~~disclosed in ~~the~~MD&A ~~first~~in ~~six~~our ~~months~~Annual Report on ~~producer~~Form ~~services~~10-K for the year ended December 31, 2005. The policies disclosed included the accounting for derivative contracts at fair value, goodwill impairment testing, employee benefit plans, regulated operations;, gas and oil operations and income taxes.

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

~~Higher~~EITF 04-13 ~~operations and maintenance expense due to lower net pension credits and increased OPEB costs and higher contractor services expense.~~

We enter into buy/sell and related agreements primarily as a means to reposition our offshore Gulf of Mexico crude oil production to more liquid marketing locations onshore. As discussed in Note 3 to our Consolidated Financial Statements, in September 2005, the FASB ratified the EITF’s consensus on Issue No. 04-13 that will require buy/sell and related agreements with the same counterparty to be presented on a net basis in the Consolidated Statements of Income if they are entered into in contemplation of one another. This new guidance is required to be applied to all new arrangements entered into, and modifications or renewals of existing arrangements, beginning April 1, 2006. We adopted EITF 04-13 on April 1, 2006, and as a result a portion of our future activity related to buy/sell arrangements will be presented on a net basis in our Consolidated Statements of Income; however, there will be no impact on our results of operations or cash flows.

Accounting for Pensions and Other Postretirement Benefits

In late 2005, the FASB added a two-phase comprehensive project to its technical agenda to reconsider the accounting for pensions and other postretirement benefits. In March 2006, the FASB issued an Exposure Draft, Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R), representing the first phase of the project. In this phase, the FASB is proposing to require that entities recognize the current economic over-funded or under-funded status of their defined benefit postretirement plans in their balance sheets effective December 31, 2006, with retrospective application required unless it is deemed impracticable. The FASB’s goal is to issue a final Statement by September 2006. We are currently assessing the impact that this new guidance will have on our results of operations and financial condition, if it is issued as drafted.

PAGE 24

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

~~The~~ITEM 2. ~~Delivery segment includes the Company~~MANAGEMENT'sS ~~regulated~~DISCUSSION ~~gas~~AND ~~distribution~~ANALYSIS ~~and~~OF ~~customer service business and nonregulated retail energy marketing operations and related products and services.~~

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

RESULTS OF OPERATIONS

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

	Three Months Ended June 30,	Six Months Ended June 30,
	2004 vs. 2003 Increase (Decrease)	2004 vs. 2003 Increase (Decrease)
	(millions)
Weather	$ (1)	$(8)
Nonregulated retail energy marketing operations	2	16
Other margins	6	8
Pension and OPEB expense	(3)	(7)
Bad debt expense	5	11
Other	8	4
Change in net income contribution	$17	$24

Results of Operations

~~Lower~~Presented below ~~regulated~~is ~~gas~~a ~~sales~~summary ~~attributable~~of toour ~~comparably~~consolidated ~~warmer~~results ~~weather;~~for the quarter ended March 31, 2006 and 2005:

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

First Quarter	2006	2005	$ Change
(millions)
Net Income	$201	$287	$(86)

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

~~Lower~~Net income ~~net~~for ~~pension~~the ~~credits~~first quarter of 2006 decreased 30% to $201 million. Our 2006 results were negatively impacted by tax adjustments and anthe ~~increase~~write-off of certain regulatory assets in ~~OPEB~~connection ~~costs;~~with the pending sale of two of our wholly-owned regulated gas distribution subsidiaries, The Peoples Natural Gas Company (Peoples) and Hope Gas, Inc. (Hope), as discussed in Note 5 to our Consolidated Financial Statements. The unfavorable impact of those adjustments was partially offset by a higher contribution from our exploration and production operations attributable to increased gas and oil production, higher realized prices for gas and oil and the impact of favorable price changes on hedges that were de-designated following Hurricanes Katrina and Rita in 2005.

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

Presented below are selected amounts related to our results of operations:

First Quarter	2006	2005	$ Change
(millions)

Operating Revenue	$ 2,825	$ 2,376	$ 449

Operating Expenses
Purchased gas	1,350	1,175	175
Electric fuel and energy purchases	65	72	(7)
Other energy-related commodity purchases	226	89	137
Other operations and maintenance	349	283	66
Depreciation, depletion and amortization	218	166	52
Other taxes	99	90	9

Other income	5	3	2
Interest and related charges	68	52	16
Income tax expense	254	165	89

An analysis of our results of operations for the first quarter of 2006 compared to the first quarter of 2005 follows:

Operating Revenue increased 19% to $2.8 billion, primarily reflecting:

A $173 million increase in other energy-related commodity sales resulting from a $138 million increase in sales of purchased oil under buy/sell arrangements by exploration and production operations due to higher oil prices ($48 million) and increased sales volumes ($90 million) and a $27 million increase in sales of extracted products, primarily due to a contractual change for a portion of our gas production processed by third parties. We now take title to and market the natural gas liquids extracted from this gas;

A $144 million increase in nonregulated gas sales revenue largely reflecting a $52 million increase from gas aggregation activities, due to higher prices ($135 million), partially offset by lower volumes ($83 million) and a $102 million increase from nonregulated retail energy marketing activities due to higher prices for contract sales. These increases were largely offset by a corresponding increase in Purchased gas expense;

PAGE 25

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

~~Exploration~~ITEM 2. &MANAGEMENT'S ~~Production~~DISCUSSION ~~Segment~~AND ANALYSIS OF

	Three Months Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
	(millions)
Net income contribution	$144	$75	$253	$159
Gas production (bcf)	67.0	70.9	136.6	140.4
Oil production (million bbls)	2.1	2.0	4.0	4.0
Average realized prices with hedging results:
Gas (per mcf)(1)	$4.05	$4.22	$4.07	$4.25
Oil (per bbl)	$25.24	$24.70	$24.78	$25.41
Average realized prices without hedging results:
Gas (per mcf)(1)	$5.67	$5.27	$5.57	$5.72
Oil (per bbl)	$37.40	$28.41	$35.78	$31.07
Other information:
DD&A (unit of production rate per mcfe)	$1.37	$1.34	$1.36	$1.30

RESULTS OF OPERATIONS

~~_____________________ bbl = barrel mcf = thousand cubic feet | mcfe = thousand cubic feet equivalent~~(Continued)

· A $122 million increase in gas and oil production revenue reflecting a $93 million increase in sales of oil production due to higher volumes (1$74 million) and increased prices ($19 million) and a $28 million increase in gas production primarily due to higher average realized prices;

~~Presented~~· ~~below,~~A on$22 anmillion ~~after-tax~~increase ~~basis,~~in ~~are~~nonregulated ~~the~~electric ~~key~~sales ~~factors~~primarily ~~impacting~~resulting ~~the~~from ~~Exploration~~increased &revenue ~~Production~~from ~~segment's~~nonregulated ~~operating~~retail ~~results:~~energy marketing operations due to higher customer contract sales rates; partially offset by

	Three Months Ended June 30,	Six Months Ended June 30,
	2004 vs. 2003 Increase (Decrease)	2004 vs. 2003 Increase (Decrease)
	(millions)
VPP revenue	$32	$50
Gas and oil-production	(11)	(16)
Gas and oil-prices	(4)	(11)
Operations and maintenance expense	30	57
DD&A-production	3	3
DD&A-rate	(3)	(8)
Income taxes	20	20
Other	2	(1)
Change in net income contribution	$ 69	$ 94

·	A $42 million decrease in other revenues largely attributable to the absence of business interruption insurance revenue recognized in 2005 associated with Hurricane Ivan.

Operating Expenses and Other Items

Purchased gas expense increased 15% to $1.4 billion, resulting from a $75 million increase related to gas aggregation activities and a $63 million increase from nonregulated retail energy marketing activities both of which are discussed in Operating Revenue. The increase also reflects $31 million in additional costs attributable to regulated gas distribution operations due to higher prices ($122 million) partially offset by lower volumes ($91 million).

Electric fuel and energy purchases expense decreased 10% to $65 million, primarily resulting from lower purchases by our nonregulated retail energy marketing operations due to customer attrition.

Other energy-related commodity purchases expense increased 154% to $226 million, reflecting a $136 million increase in purchases of oil under buy/sell arrangements by exploration and production operations as discussed in Operating Revenue.

Other operations and maintenance expense increased 23% to $349 million, primarily resulting from:

· A $159 million charge from the write-off of certain regulatory assets related to the pending sale of Peoples and Hope;

·	A $27 million increase attributable to higher production and transportation costs related to gas and oil production;

·	A $25 million increase in expenses for regulated gas operations related to low income home energy assistance programs. These expenditures are recovered through rates and do not impact our net income; and

·	A $15 million increase in insurance costs for exploration and production operations due primarily to insurance premium loss adjustments incurred following the 2005 hurricanes; partially offset by

·	A $118 million benefit resulting from favorable price changes in the fair value of certain gas and oil derivatives that were de-designated as hedges following the 2005 hurricanes; and

·	The impact of a $49 million loss recognized in 2005 reflecting the discontinuance of hedge accounting for certain oil derivatives 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.

Depreciation, depletion and amortization expense (DD&A) increased 31% to $218 million, largely due to the impact of higher exploration and production finding and development costs as well as increased oil production.

Other taxes increased 10% to $99 million, primarily due to higher severance taxes associated with increased commodity prices and higher payroll taxes resulting from incentive-based compensation paid in 2006.

Interest and related charges increased 31% to $68 million primarily due to the impact of additional borrowings from Dominion’s money pool and higher interest rates on those borrowings.

Income tax expense reflects an increase in our effective tax rate to 55.9% due to the recognition of additional taxes associated with the planned sale of Peoples and Hope as discussed in Note 5 to our Consolidated Financial Statements.

PAGE 26

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

~~Recognition~~ITEM 2. ofMANAGEMENT'S ~~revenue~~DISCUSSION inAND ~~connection~~ANALYSIS ~~with~~OF ~~deliveries under VPP agreements;~~

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

~~Higher oil production reflecting the beginning of production related to the deepwater Gulf of Mexico Devils Tower project;~~(Continued)

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

ASegment results ~~higher~~include ~~rate~~the ~~for~~impact ~~depreciation,~~of ~~depletion~~intersegment revenues and ~~amortization (DD&A)~~expenses, ~~primarily~~which ~~reflecting~~may result ~~higher~~in ~~industry~~intersegment ~~finding~~profit and ~~development~~loss. ~~costs,~~Presented below is a ~~reduction~~summary inof contributions ~~production~~by ~~volumes~~our ~~associated~~operating ~~with~~segments ~~the~~to ~~VPP~~net ~~transactions,~~income ~~and~~for ~~increased~~the ~~acquisition~~quarter ~~costs;~~ended March 31, 2006 and 2005:

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


First Quarter	2006	2005	$ Change
	(millions)
Delivery	$85	$104	$(19)
Energy	88	80	8
E&P	213	104	109
Primary operating segments	386	288	98

Corporate	(185)	(1)	(184)
Consolidated	$201	$287	$(86)

~~Corporate and Other also includes CNGI and other minor subsidiaries.~~Delivery

Delivery ~~Presented~~ includes ~~below~~our ~~are~~regulated ~~the~~gas ~~Corporate~~distribution and ~~Other~~customer ~~segment's~~service ~~after-tax~~business, ~~operating~~as ~~results~~well as ~~for~~nonregulated ~~the~~retail ~~three~~energy marketing operations and ~~six~~related ~~months~~products ~~ended~~and services. ~~June~~Presented ~~30,~~below ~~2004~~are ~~and~~operating ~~2003~~statistics related to our Delivery operations:

	Three Months Ended June 30,		Six Months Ended June 30,
First Quarter	2006	2005	% Change
	2004	2003	2004	2003
Gas throughput (bcf):
	(millions)
Gas sales	50	63	(21)%
Net loss	$ (28)	$ (23)	$ (8)	$ (33)
Gas transportation	87	92	(5)
Heating degree days (gas service area) (1)	2,580	3,022	(15)
Gas delivery customer accounts(2):
Gas sales	996	1,071	(7)
Gas transportation	704	635	11
Unregulated retail energy marketing customer accounts(2)	1,199	1,131	6

bcf = ~~Three~~ billion ~~Months~~cubic ~~Ended June 30, 2004 vs. 2003~~feet

~~Corporate~~(1) ~~and~~Heating ~~Other~~degree ~~experienced~~days aare ~~net~~the ~~loss~~differences ofbetween ~~$28~~the ~~million~~average temperature for ~~2004,~~each ~~compared~~day toand a65 ~~net loss of $23 million in 2003. The 2004 results primarily reflect an increase in an income tax valuation allowance related to CNGI investments~~degrees, ~~partially~~when ~~offset by an $8 million gain on~~ the ~~sale~~average oftemperature ais ~~portion~~less ofthan ~~CNGI's~~65 ~~investment in an Australian pipeline business in June 2004~~degrees. The 2003 net loss primarily reflects impairment losses totaling $40 million ($25 million after-tax) related primarily to CNGI's investments in the Australian pipeline business and a small generation facility in Kauai, Hawaii that was sold in December 2003.

(2) In ~~Six Months Ended June 30~~ thousands, ~~2004~~at ~~vs.~~period ~~2003~~end.

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

	First Quarter 2006 vs. 2005 Increase (Decrease)


	(millions)
Weather	$ (12)
Other margins⁽¹⁾	(9)
Interest expense	(6)
Nonregulated retail energy marketing operations⁽²⁾	6
Other	2
Change in net income contribution	$ (19)

(1)	Reflects reduced customer usage, due in part to sensitivity to rising gas prices.

(2) Largely reflects higher electric and gas margins.

PAGE 27

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

~~A $5 million after-tax loss associated with the cumulative effect of a change in accounting principle related to the adoption of SFAS No~~ITEM 2. ~~143~~MANAGEMENT'S onDISCUSSION ~~January~~AND 1,ANALYSIS ~~2003~~OF ~~attributable to the Energy segment; and~~

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

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

(Continued)

~~_______________~~Energy

(Energy includes our tariff-based natural gas transmission pipeline and storage businesses and an LNG import and storage facility. It also includes certain natural gas production operations and producer services, which consist of aggregation of gas supply and related wholesale activities. Presented below are operating statistics related to our Energy operations:

First Quarter	2006	2005	% Change
Gas sales (bcf)	50	61	(18)%
Gas transportation (bcf)	234	301	(22)

Presented below, on an after-tax basis, are the key factors impacting Energy’s net income contribution:

	First Quarter 2006 vs. 2005 Increase (Decrease)


	(millions)
Producer services⁽¹⁾	$ 14
Gas transmission rate settlement⁽²⁾	(9)
Other	3
Change in net income contribution	$8

(1)	Higher gains resulting from the impact of favorable price changes on gas marketing activities associated with certain contractual assets.

(2)	Represents lower natural gas transportation and storage revenues as a result of a rate settlement that went into effect July 1, 2005.

E&P

E&P includes our gas and oil exploration, development and production business. 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. Presented below are operating statistics related to our E&P operations:

First Quarter	2006	2005	% Change
Gas production (bcf)	60.9	60.1	1%
Oil production (million bbls)	5.7	3.5	63
Average realized prices with hedging results
Gas (per mcf)⁽¹⁾	$5.43	$4.31	26
Oil (per bbl)	38.56	28.48	35
Average realized prices without hedging results
Gas (per mcf)⁽¹⁾	8.10	6.26	29
Oil (per bbl)	53.90	45.44	19
DD&A (unit of production rate per mcfe)	1.76	1.47	20

bbl = barrel

mcf = thousand cubic feet

mcfe = thousand cubic feet equivalent

(1)

Excludes $49 million and $67 million of revenue recognized in the first quarter of 2006 and 2005, respectively, under the volumetric production payment (VPP) agreements described in Note 10 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2005.

PAGE 28

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

ITEM ~~Factors~~ 2. that may cause actual results to differ materially from those indicated in any forward-looking statement include weather conditions; governmental regulations; cost of environmental compliance; fluctuations in energy-related commodities prices and the effect these could have on the CompanyMANAGEMENT'sS ~~earnings,~~DISCUSSION ~~liquidity~~AND ~~position~~ANALYSIS ~~and~~OF the underlying value of its assets; trading counterparty credit risk; capital market conditions, including price risk due to marketable securities held as investments in trusts and benefit plans; fluctuations in interest rates; changes in rating agency requirements and ratings; changes in accounting standards; collective bargaining agreements and labor negotiations; the risks of operating businesses in regulated industries that are becoming deregulated; political and economic conditions (including inflation and deflation). Other more specific risk factors are as follows:

RESULTS ~~The~~ OF ~~Company's operations are weather sensitive.~~OPERATIONS

~~The Company is subject to complex governmental regulation that could adversely affect its operations.~~(Continued)

Presented ~~Costs~~ below, ofon ~~environmental~~an ~~compliance~~after-tax basis, ~~liabilities~~are ~~and~~the ~~litigation~~key ~~could~~factors ~~exceed~~impacting ~~the Company'~~E&P’s ~~estimates~~net income contribution:

The use of derivative instruments could result in financial losses.

	First Quarter 2006 vs. 2005 Increase (Decrease)


	(millions)

Operations and maintenance ⁽¹⁾	$85
Gas and oil—prices	59
Gas and oil—production⁽²⁾	50
DD&A	(34)
Business interruption insurance	(28)
Interest expense	(12)
Change in state income tax estimate⁽³⁾	(11)
Change in net income contribution	$ 109

(1)	Lower operations and maintenance expenses, primarily reflecting the impact of favorable changes in the fair value of certain gas and oil derivatives that were de-designated as hedges following the 2005 hurricanes, partially offset by increased production costs.

(2)	Represents an increase in oil production primarily resulting from deepwater oil production at the Gulf of Mexico Devils Tower, Triton and Goldfinger projects.

(3)	Reflects increased income tax expense largely due to the effect of a revision to estimated state income tax apportionment percentages on accumulated deferred income taxes during the first quarter of 2006.

Included below are the volumes and weighted average prices associated with economic hedges in place as of March 31, 2006 by applicable time period. Prior cash flow hedges for which hedge accounting was discontinued due to production interruptions caused by Hurricanes Katrina and Rita, and for which amounts were reclassified from AOCI to earnings upon the discontinuance of hedge accounting, are excluded from the following table:


	Natural Gas		Oil
Year	Hedged production (bcf)	Average hedge price (per mcf)	Hedged production (million bbls)	Average hedge price (per bbl)
2006	147.5	$4.64	10.4	$25.05
2007	189.7	5.77	10.0	33.41
2008	106.7	7.78	5.0	49.36

Corporate

Corporate includes our corporate functions, including the activities of CNGI, our power generating facility and other minor subsidiaries. Presented below are the Corporate segment’s after-tax results:

	First Quarter
	2006	2005	Change
(millions)
Specific items attributable to
operating segments	$(106)	$--	$(106)
Other corporate operations	(79)	(1)	(78)
Total net expense	$(185)	$(1)	$(184)

PAGE 29

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

ITEM ~~The~~ 2. ~~Company~~MANAGEMENT'sS ~~exploration~~DISCUSSION ~~and~~AND ~~production~~ANALYSIS ~~business~~OF ~~is dependent on factors that cannot be predicted or controlled.~~

RESULTS An OF ~~inability to access financial markets could affect the execution of the Company's business plan.~~OPERATIONS

~~Changing rating agency requirements could negatively affect the Company's growth and business strategy.~~(Continued)

Specific ~~Potential~~ Items ~~changes~~Attributable into ~~accounting~~Operating ~~practices may adversely affect the Company's financial results~~Segments

We reported expenses of $106 million in 2006 in the Corporate segment attributable to the Delivery segment, primarily reflecting a $159 million ($94 million after-tax) charge resulting from the write-off of certain regulatory assets related to the pending sale of Peoples and Hope.

Other Corporate Operations

We reported net expenses of $79 million in 2006 associated with other corporate operations as compared to net expenses of $1 million in 2005, primarily reflecting tax adjustments recorded in 2006 associated with the pending sale of Peoples and Hope. We recognized $107 million of deferred tax liabilities in accordance with EITF Issue No. 93-17, as discussed in Note 5 to the Consolidated Financial Statements. The recognition of these liabilities was partially offset by a $25 million tax benefit from the partial reversal of previously recorded valuation allowances on deferred tax assets, representing certain federal and state tax loss carryforwards, since these carryforwards are expected to be utilized to offset capital gain income generated from the sale.

Credit Risk

Our exposure to potential credit risk results primarily from our marketing of natural gas and sales of gas and oil production. Presented below is a summary of our gross credit exposure as of March 31, 2006. We calculate our gross credit exposure for each counterparty as the unrealized fair value of derivative contracts plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral.

	Gross Credit Exposure
	(millions)
Investment grade⁽¹⁾	$433
Non-investment grade⁽²⁾	19
No external ratings:
Internally rated—investment grade⁽³⁾	21
Internally rated—non-investment grade⁽⁴⁾	145
Total	$618

________________

(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 2% of the total gross credit exposure.

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

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

PAGE 30

CONSOLIDATED NATURAL GAS COMPANY

ITEM 4 2. ~~CONTROLS~~MANAGEMENT'S DISCUSSION AND ~~PROCEDURES~~ANALYSIS OF

~~Senior~~RESULTS OF 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. OPERATIONS

On December 31, 2003, the Company adopted FIN 46R for its interests in special purpose entities referred to as SPEs and, as a result, has included in its consolidated financial statements those SPEs described in Note 3 to the Consolidated Financial Statements in its Annual Report on Form 10-K for the year ended December 31, 2003. The Consolidated Balance Sheet as of June 30, 2004 reflects $219 million of net property, plant and equipment and deferred charges and $234 million of related debt attributable to the SPEs. As these SPEs are owned by unrelated parties, the Company does not have the authority to dictate or modify, and therefore cannot assess, the disclosure controls and procedures or internal control over financial reporting in place at these entities. (Continued)

Other Matters

Future Environmental Regulations

In 1997, the U.S. signed an International Protocol (Protocol) to limit man-made greenhouse emissions under the United Nations Framework Convention on Climate Change. However, the Protocol will not become binding unless approved by the U.S. Senate. Currently, the Bush Administration has indicated that it will not pursue ratification of the Protocol and has set a voluntary goal of reducing the nation’s greenhouse gas emission intensity by 18% over the period 2002-2012. Several legislative proposals that include provisions seeking to impose carbon taxes on fuels or mandatory reductions of greenhouse gas emissions are under consideration in the U.S. Congress. The cost of compliance with the Protocol, taxes, or other mandatory greenhouse gas reduction obligations could be significant. Given the highly uncertain outcome and timing of future action, if any, by the U.S. federal government on this issue, we cannot predict the financial impact of future climate change actions on our operations at this time.

Minimum Service Standards

In January 2006, the Public Utilities Commission of Ohio (Ohio Commission) issued an Order adopting rules establishing minimum service standards for natural gas companies. We estimate that, if implemented as written, these rules would result in increased expenditures in the range of $10 million to $15 million per year. We have filed an application for rehearing along with certain other Ohio gas distribution companies. The Ohio Commission has granted that request.

PAGE 31

CONSOLIDATED NATURAL GAS COMPANY ~~PART II. OTHER INFORMATION~~

ITEM 5 4. ~~OTHER~~CONTROLS ~~INFORMATION~~AND PROCEDURES

Senior ~~Other~~ management, ~~FERC~~including ~~Matter~~the Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our 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 our disclosure controls and procedures are effective. There were no changes in our internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

~~The~~In accordance ~~Company~~with ~~and~~FIN 46R, we ~~the~~have ~~Federal~~included ~~Energy~~in ~~Regulatory~~our ~~Commission~~Consolidated ~~(FERC)~~Financial ~~have~~Statements ~~reached~~ a ~~settlement~~VIE ofthrough awhich we have ~~self-reported~~financed ~~infraction~~and ofleased ~~FERC~~a ~~regulations~~power ~~involving~~generation ~~data~~project. ~~sharing~~Our ofConsolidated ~~non-public~~Balance Sheet ~~gas~~as ~~storage~~of ~~information.~~March ~~Under the settlement~~31, ~~the~~2006 ~~Company~~reflects ~~will~~$206 ~~pay~~million aof ~~$500~~net property,~~000~~ ~~civil~~plant ~~penalty,~~and equipment ~~refund~~and deferred charges and $~~4.5~~234 million of related debt attributable to the ~~its~~VIE. ~~non-affiliated~~As ~~natural~~this ~~gas~~VIE ~~storage~~is ~~customers~~owned ~~and~~by ~~enhance~~unrelated ~~internal~~parties, ~~training~~we ~~and~~do ~~oversight~~not ofhave ~~employees~~the ~~who~~authority to ~~handle~~dictate ~~non-public~~or modify, ~~market-sensitive~~and ~~data.~~therefore ~~The~~cannot ~~Company~~assess, ~~has~~the ~~previously~~disclosure ~~accrued~~controls and procedures ~~the~~or ~~amounts~~internal tocontrol beover ~~paid~~financial ~~pursuant~~reporting toin ~~the~~place ~~settlement~~at ~~agreement~~this entity.

Statoil ASA (Statoil) Agreement

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

Rate Matters - Gas Distribution

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

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits:
	3.1	Certificate of Incorporation of Consolidated Natural Gas Company (Exhibit (3A)(i) to Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference).
	3.2	Certificate of Amendment of Certificate of Incorporation, dated January 28, 2000 (Exhibit (3A)(ii) to Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference).
	3.3	Bylaws as in effect on December 15, 2000 (Exhibit 3B to Form 10-K for the fiscal year ended December 31, 2000, File No. 1-3196, incorporated by reference).
	10.1	$1,500,000,000 3-Year Credit Agreement among Dominion Resources, Inc., Virginia Electric and Power Company, Consolidated Natural Gas Company and JPMorgan Chase Bank, as Administrative Agent for the Lenders, dated May 27, 2004 (filed herewith).

PAGE 32

CONSOLIDATED NATURAL GAS COMPANY ~~PART II. OTHER INFORMATION~~

~~ITEM 6~~PART II. ~~EXHIBITS~~OTHER ~~AND REPORTS ON FORM 8-K~~INFORMATION

(a) Exhibits (continued):
	12	Ratio of earnings to fixed charges (filed herewith).
	31.1	Certification by Registrant's Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
	31.2	Certification by Registrant's Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
	32	Certification to the Securities and Exchange Commission by Registrant's Chief Executive Officer and Chief Financial Officer, as required by Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
	99	Condensed consolidated earnings statements (unaudited) (filed herewith).

ITEM 1. LEGAL PROCEEDINGS

~~(b)~~From time to ~~Reports~~time, we are 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 us, or permits issued by various local, state and federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on ~~Form~~these ~~8-K:~~matters. In addition, in the ordinary course of business, we are involved in various legal proceedings. Management believes that the ultimate resolution of these proceedings will not have a material adverse effect on our financial position, liquidity or results of operations.

In March 2006, Peoples and Equitable Resources, Inc. (Equitable) filed a joint petition with the Pennsylvania Public Utility Commission seeking approval of the purchase by Equitable of all of the stock of Peoples and Hope. In April 2006, Hope and Equitable filed a joint petition seeking West Virginia Public Service Commission approval of the purchase by Equitable of all of the stock of Hope.

Dominion Transmission Inc., (DTI) has reached an agreement in principle on a proposed Consent Order and Agreement (COA) with the Pennsylvania Department of Environmental Protection (PADEP) which would supersede a 1990 COA between the parties. The agreement in principle resolves longstanding groundwater contamination issues at several DTI compressor stations in Pennsylvania and includes a penalty of $850,000 to be paid to PADEP and the Pennsylvania Department of Conservation and Natural Resources to resolve alleged violations. Negotiations are ongoing with both agencies to finalize language and payment mechanisms. As of March 31, 2006, DTI has accrued $850,000 for the penalty.

Before being acquired by us, Louis Dreyfus Natural Gas Corp. (Louis Dreyfus) was one of numerous defendants in a lawsuit consolidated and pending in the 93^rd Judicial Court in Hidalgo County, Texas. The lawsuit alleged that gas wells and related pipeline facilities operated by Louis Dreyfus and other facilities operated by other defendants caused an underground hydrocarbon plume in McAllen, Texas. In April 2006, we entered into a settlement agreement with the plaintiffs resolving all of their claims against us. We remain subject, however, to a cross-claim and potential indemnity issues with certain of the other defendants that were not a part of the settlement. We do not expect the resolution of these remaining claims to have a material adverse effect on our results of operations or financial condition.

See Other Matters in MD&A for discussion on various regulatory proceedings to which we are a party.

ITEM 1A. RISK FACTORS

Our business is influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond our control. We have identified a number of these risk factors in our Annual Report on Form 10-K for the year ended December 31, 2005, which factors should be taken into consideration when reviewing the information contained in this report. With the exception of the risk factors below, which have been modified to take into account a March 2006 downgrade by Moody’s of our credit rating and recent developments relating to business interruption insurance, there have been no material changes with regard to the risk factors previously disclosed in our most recent Form 10-K. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, see Forward-Looking Statements in MD&A.

Changing rating agency requirements could negatively affect our growth and business strategy. As of May 1, 2006, our senior unsecured debt is rated BBB, stable outlook, by Standard & Poor’s; Baa1, stable outlook, by Moody’s; and BBB+, stable outlook, by Fitch Ratings Ltd. (Fitch). In order to maintain our current credit ratings in light of existing or future requirements, we may find it necessary to take steps or change our business plans in ways that may adversely affect our growth and earnings. A reduction in our credit ratings by Standard & Poor’s, Moody’s or Fitch could increase our borrowing costs and adversely affect operating results and could require us to post additional collateral in connection with some of our marketing activities.

PAGE 33

CONSOLIDATED NATURAL GAS COMPANY

PART II. OTHER INFORMATION

(Continued)

ITEM 1A. RISK FACTORS

(Continued)

Our 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 our assets. Factors that may affect our financial results include damage to or suspension of operations caused by weather, fire, explosion or other events to our or third party gas and oil facilities, fluctuations in natural gas and crude oil prices, results of future drilling and well completion activities and our 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 our financial results by causing a permanent write-down of our 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.

We maintain business interruption insurance for offshore operations associated with our exploration and production business. We have placed our insurers on notice that we have suffered substantial property damage and business interruption loss related to Hurricanes Katrina and Rita. We are aware that during the claim adjusting process, certain underwriters will take positions adverse to coverage for various parts of the claim. A failure to realize the full value of our claims could negatively affect our results of operations. Additionally, the increased level of hurricane activity in the Gulf of Mexico is likely to significantly increase the cost of business interruption insurance, reduce its availability and may make it unavailable on commercially reasonable terms. Inability to insure our offshore Gulf of Mexico operations, or the more limited coverage of alternative options, could adversely affect our results of operations.

PAGE 34

CONSOLIDATED NATURAL GAS COMPANY

PART II. OTHER INFORMATION

(Continued)

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	$3.0 billion Five-Year Credit Agreement dated February 28, 2006 among Dominion Resources, Inc., Virginia Electric and Power Company, Consolidated Natural Gas Company, JPMorgan Chase Bank, N.A., as Administrative Agent, Citibank, N.A., as Syndication Agent and Barclays Bank PLC, The Bank of Nova Scotia and Wachovia Bank, National Association, as Co-Documentation Agents and other lenders named therein. (Exhibit 10.1, Form 8-K filed March 3, 2006, File No. 1-3196, incorporated by reference).
	10.2	$1.70 billion Amended and Restated Five-Year Credit Agreement dated February 28, 2006 among Consolidated National Gas Company, Barclays Bank PLC, as Administrative Agent, Barclays Bank PLC and KeyBank National Association, as Syndication Agents and SunTrust Bank, The Bank of Nova Scotia and ABN AMRO Bank N.V., as Co-Documentation Agents and other lenders as named therein. (Exhibit 10.2, Form 8-K filed March 3, 2006, File No. 1-3196, incorporated by reference).
	10.3	$1.05 billion 364-Day Credit Agreement dated February 28, 2006 among Consolidated Natural Gas Company, Barclays Bank PLC, as Administrative Agent, Barclays Bank PLC and KeyBank National Association, as Syndication Agents, The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch and Mizuho Corporate Bank, Ltd., as Co-Documentation Agents and other lenders as named therein. (Exhibit 10.3, Form 8-K filed March 3, 2006, File No. 1-3196, 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).
	99	Condensed consolidated earnings statements (unaudited) (filed herewith).

SIGNATURE

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

	CONSOLIDATED NATURAL GAS COMPANY Registrant
August 4, 2004	/s/ Steven A. Rogers
May 3, 2006	/s/ Steven A. Rogers
	Steven A. Rogers Vice President and Controller (Principal Accounting Officer)
	Steven A. Rogers Senior Vice President and Controller (Principal Accounting Officer)

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